20110202Oral Argument Vol 1, pp 1-112, Boise.pdf

ORIGINAL.BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY, AVISTA
COBPORATION, AND PACIFICORP DBA
ROCKY MOUNTAIN POWER TO ADDRESS
AVOIDED COST ISSUES AND TO ADJUST
THE PUBLISHED AVOIDED COST RATE
ELIGIBILITY CAP.
CASE NO. GNR-E-10-04
ORAL ARGUMENT
BEFORE
COMMISSIONER MARSHA SMITH (Presiding)
COMMISSIONER JIM KEMPTON
COMMISSIONER MACK REDFORD.
PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:January 27, 2011
VOLUME I - Pages 1 - 112
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CSB REPORTING
Constance S. Bucy, CSR No. 187
23876 Applewood Way * Wilder, Idaho 83676
[phone] * [phone]
Email csb(qheritagewifi.com
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1 APPEARANCES
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3 For the Staff:Kristine Sasser, Esq.
Deputy Attorney General
472 West Washington
Boise, Idaho 83720-0074
Donovan Walker, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
LOVINGER KAUFMANN
by Kenneth E. Kaufmann, Esq.
825 NE. Multnomah
Suite 925
Portland, Oregon 97232-2150
Michael G. Andrea, Esq.
Avista Corporation
1411 East Mission Avenue
Spokane, Washington 99202
RICHARDSON & 0 i LEARY
by Peter J. Richardson, Esq.
Post Office Box 7218
Boise, Idaho 83702
Williams Bradbury, P. C.
by Ronald L. Williams, Esq.
1015 West Hays Street
Boise, Idaho 83702
Mimura Law Offices, PLLC
by R. Greg Ferney, Esq.
2176 East Franklin Road
Meridian, Idaho 83642
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6 For Idaho Power Company:
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9 For PacifiCorp dba Rocky
Mountain Power:
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For Avista Corporation:
For Board of County
Commissioners, Grand View
Solar, Exergy Development
Group & NI PPC:
For Cedar Creek Wind and
Dynamis Energy, LLC:
Interconnect Solar
Development, LLC:
(Telephonically)
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APPEARANCES
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1 A P PEA RAN C E S (Continued)
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3 For Renewable EnergyCoalition:
(Telephonically)
John R. Lowe
12050 SW Tremont Street
Portland, Oregon 972254
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For Intermountain
Wind, LLC:
McDEVITT & MILLER
by Dean J. Miller, Esq.
Post Office Box 2564
Boise, Idaho 83701-25647
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For North Side Canal
Company & Twin Falls
Canal Company:
Barker Rosholt & Simpson
by Shelley M. Davis, Esq.
Post Office Box 2139
Boise, Idaho 8370110
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For Blue Ribbon Energy:
(Telephonically)Arron F. Jepson
and M. J. Humphries
Blue Ribbon Energy, LLC
10660 South 540 East
Sandy, Utah 84070
CSB REPORTING
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APPEARANCES
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1 BOISE, IDAHO, THURSDAY, JANUARY 27,2011,9:30 A. M.
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4 COMMISSIONER SMITH: Good morning, ladies
5 and gentlemen. This is the time and place set for an
6 oral ,argument in Idaho Public Utili ties Commission Case
7 No. GNR-E-10-04. It's further identified as in the
8 mattet of the joint petition of Idaho Power Company,
9 Avista Corporation and PacifiCorp dba Rocky Mountain
10 Power to address avoided cost issues and to adjust the
11 published avoided cost rate eligibility cap.
12 My name is Marsha Smith and I'm going to
13 Chair today i shearing. On my left is Commissioner Jim
14 Kempton who is president of the Commission. On my right
15 is Commissioner Mack Redford and the three of us are the
16 Public Utilities Commission who will hear and decide
17 these issues. Can you hear me all right?
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THE AUDIENCE: No.
COMMISSIONER SMITH: No. I don i t see the
20 people who adj ust the machine.
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MR. LOBB: Do you want the sound changed?
COMMISSIONER SMITH: Yes, so that they can
23 hear better. Thank you, Randy. We i re going to begin
24 today by taking the appearances of the parties and we'll.25 start with the applicants. Mr. Walker.
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1 MR. WALKER: Yes, thank you,
2 Madam Chairman, Donovan Walker, legal counsel for Idaho
3 Power Company.
4 COMMISSIONER SMITH: Okay.
5 MR. KAUFMANN: Good morning, Chairman __
6 COMMISSIONER SMITH: Is your red light on?
7 MR. KAUFMANN: Good morning, I'm Ken
8 Kaufmann. I i m counsel for PacifiCorp and I have Bruce
9 Griswold, PacifiCorp manager of origination, with me.
10 COMMISSIONER SMITH: Mr. Kaufmann, could
11 you please spell your last name for me?
12 MR. KAUFMANN: Yes, it's
13 K-a-u-f-m-a-n-n.
14 COMMISSIONER SMITH: Thank you.
15 MR. ANDREA: Good morning, Madam Chair,
16 Commissioners, Mike Andrea, legal counsel for Avista
17 Corporation.
COMMISSIONER SMITH: Mr. Andrea, thank
19 you. I see Mr. Richardson is with us. I think you have
20 a number of clients.
21 MR. RICHARDSON: Thank you,
22 Madam Chairman. Peter Richardson with the firm
23 Richardson & 0' Leary. I'm appearing here this morning on
24 behalf of the Board of County Commissioners of Adams
25 County, several of the commissioners are present with us
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1 this morning; Grand View Solar; Exergy Development Group
2 of Idaho; and the Northwest and Intermountain Power
3 Producers Coalition, and I will be speaking today on
4 behalf of all four clients, similarly-situated clients,
5 and to the extent, Madam Chairman, we're permitted to
6 introduce evidentiary exhibits, we would prefer to use
7 the series 400 to 500 under the Northwest and
8 Intermountain Power Producers Coalition's exhibit
9 numbers.
10 COMMISSIONER SMITH: Okay; so in my list,
11 Mr. Richardson, you're also representing J. R. Simplot,
12 but you're not here on behalf of them today?
13 MR. RICHARDSON: That's correct, Madam
14 Chairman.
15 COMMISSIONER SMITH: All right. Is there
16 anyone here on behalf of J.R. Simplot?
1 7 Cedar Cree k.
18 MR. WILLIAMS: Ronald L. Williams,
19 Williams & Bradbury, on behalf of Cedar Creek Wind, LLC,
20 as well as Dynamis Energy.
COMMISSIONER SMITH: How about the
22 Renewable Energy Coalition?
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24 is John Lowe.
MR. LOWE: We're attending by phone. This
.25 COMMISSIONER SMITH: Mr. Lowe, could you
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1 please spell your last name?
2 MR. LOWE: L-o-w-e.
3 COMMISSIONER SMITH: Thank you.
4 Interconnect Solar?
5 Mr. FERNEY: Yes, good morning, Greg
6 Ferney, F-e-r-n-e-y, for Interconnect Solar.
7 COMMISSIONER SMITH: Intermountain Wind.
8 MR. MILLER: Thank you, Madam Chairman.
9 Dean J. Miller appearing on behalf of Intermountain Wind.
10 I might say I'm also authorized to speak today on behalf
11 of the Idaho Conservation League and for the Renewable
12 Northwest Proj ect, both of which filed public comments
13 but not formal interventions. Mr. Ben Otto of the Idaho
14 Conservation League is here and Ms. Megan, director of
15 the Renewable Northwest proj ect, is here and both are
16 attorneys and both are available if the Commission has
17 any questions for them.
18 COMMISSIONER SMITH: Right now it sounds
19 like it i S not their intention to make presentations.
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MR. MILLER: That's correct.
COMMISSIONER SMITH: Thank you.
23 relying on me.
MR. MILLER: Wisely or unwisely, they're
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COMMISSIONER SMITH: Very wisely, I might
say.
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1 How about the North Side Canal Company?
2 MS. DAVIS: Shelley Davis, Commissioner,
3 for Twin Falls Canal Company and North Side Canal
4 Company. I took a seat in the peanut gallery because it
5 looks like that area is
6 COMMISSIONER SMITH: Ms. Davis, I think
7 there i s a chair for you right at the front here.
8 MS. DAVIS: Okay.
9 COMMISSIONER SMITH: How about Birch
10 Power? How about Idaho Windfarms? And Blue Ribbon
11 Energy?
12 MR. JEPSON: Yes, we're appearing by
13 phone. Arron Jepson and M. J. Humphries.
14 COMMISSIONER SMITH: Mr. Jepson, could you
15 please spell your name?
16 MR. JEPSON: My first name is spelled with
17 one "a" and two "rls," A-r-r-o-n. Last name is Jepson,
18 J-e-p-s-o-n.
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20 and for the Commission Staff.
COMMISSIONER SMITH: Thank you very much,
21 MS. SASSER: Good morning, Madam Chair,
22 Kristine Sasser, attorney for Commission Staff.
23 COMMISSIONER SMITH: All right, according
24 to my list, those are the intervenors and parties to this
25 case and so those are the people who will be speaking
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1 today, so before we begin taking the statements, this is
2 an oral argument.Parties have filed written comments
3 and today is the day to not repeat everything you said in
4 your comments, but to summarize and, I guess, emphasize
5 if you feel the necessity and be available for questions
6 from the Commission if they have them.
7 Are there any preliminary matters that
8 need to come before the Commission before we start with
9 statements of the applicants? Mr. Richardson.
10 MR. RICHARDSON: Madam Chairman, we have a
11 motion to strike pending and I was wondering if we could
12 address that initially.
13 COMMISSIONER SMITH: We certainly could.
14 MR. RICHARDSON: Thank you.
15 Madam Chairman, PacifiCorp i s filing of Bruce Griswold IS
16 testimony at the eleventh hour with its reply comments
17 underscores the need to hold an evidentiary hearing in
18 this matter. NIPPC filed a motion to strike which is
19 clearly warranted given that the case is being processed
20 under modified procedure and given the fact that no other
21 party has had an opportunity to file testimony and no
22 hearings have been scheduled.
23 Madam Chairman, we're prepared to call a
24 witness today to discuss the inadequacy of the integrated
25 resource process, methodology for setting avoided cost
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1 rates.In addition, we are prepared to offer into
2 evidence all of the production request responses we
3 relied on in our comments; however, we are infirmed in
4 our ability unless the utili ties present a witness to
5 which I can lay a foundation for each response or unless
6 all parties stipulate to admit the production request
7 responses as uncontested evidentiary exhibits.
8 In addition, Madam Chairman, I would like
9 the Commission to take official notice of the orders and
10 other public documents referenced in our comments and I
11 have a motion to that effect that, with your indulgence,
12 I would circulate now.
13 COMMISSIONER SMITH: Sure.
14 (Mr. Richardson distributing documents.)
15 COMMISSIONER SMITH: While he's passing
16 those out, do you have anything further you would li ke
17 to--
18 MR. RICHARDSON: Yes, Madam Chairman. We
19 would li ke the Commission to take official notice of
20 three documents related to coal costs that support our
21 comments. One is the settlement agreement that the
22 Environmental Protection Agency reached with the parties
23 in the final rulemaking. The other is the Oregon Senate
24 Natural Resources Committee report on greenhouse gas
25 emissions, and the final is Rocky Mountain Power's parent
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1 corporation's, the MidAmerican Holdings Company, comments
2 in the coal combustion residual rulemaking, all of which
3 support our comments related to the ability of renewable
4 energy proj ects to allow the utili ties to reduce
5 generation from coal-fired power plants allowing them
6 to -- actually, it impacts the avoided cost rate and the
7 cost of renewable energy.
8 COMMISSIONER SMITH: Well, Mr. Richardson,
9 I'm getting confused because this is not a proceeding
10 today to argue about the costs. I mean, the Commission
11 clearly outlined in its Order that we wanted comments on
12 three things: the advisability of reducing the
13 eligibility cap; if the eligibility cap is reduced, the
14 appropriateness of exempting non-wind QF proj ects from
15 that reduced eligibility cap; and the consequences of
16 dividing larger wind projects into 10 average megawatt
17 proj ects in order to take advantage of the published
18 avoided cost rate.
19 MR. RICHARDSON: Thank you,
20 Madam Chairman. As pointed out in our comments, the
21 advisabili ty of reducing the eligibility cap is crucial
22 to understanding what happens when the eligibility cap is
23 reduced, meaning the integrated resource procedure,
24 process is used by all three utili ties and that process
25 does not calculate an accurate or even nearly accurate
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1 avoided cost rate, meaning that if the Commission reduces
2 the eligibility cap for published rates that you will not
3 have a methodology that creates an avoided cost rate that
4 comports with PURPA and, therefore, you will have
5 effectively put in a moratorium on new PURPA projects,
6 and it's crucial to your understanding of the process
7 that we are able to make the case factually that the IRP
8 methodology is fatally flawed and that's what these
9 documents go to.
10 COMMISSIONER SMITH: Well, the
11 Commission's decision on where the level of the cap
12 should be so long as it i S above what the law requires is
13 one of a policy decision in my mind.
MR. RICHARDSON: The Commission is
15 obligated to implement PURPA to allow renewable energy
16 PURPA QFs to sell power to the utili ties at the
17 utilities i full avoided cost rate and the IRP methodology
18 does not do that.
19 COMMISSIONER SMITH: On your motion for
20 the Commission to take official notice, I will note that
21 i believe, although I don i t have a copy of the procedural
22 rules sitting in front of me, that the Commission does
23 have the authority to take official notice of its own
24 orders and those of other -- thank you, Mr. Howell, I.25 appreciate that. We can take official notice after
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1 gi ving parties appropriate opportunity to respond, so I
2 think your passing this out gives people notice of what
3 you want us to take notice of and certainly we can take
4 notice of our own orders and those of any other
5 regulatory agency, state or federal, matters of common
6 knowledge, technical, financial or scientific facts,
7 matters judicially noticeable and data contained in
8 periodic reports of regulated utili ties filed with the
9 Commission or federal agencies. So as long as they fall
10 in one of those categories, there i s no problem with us
11 taking notice.
12 MR. RICHARDSON: Thank you,
13 Madam Chairman, and I believe all of the points that have
14 been cited in our motion fall into those categories.
15 COMMISSIONER SMITH: Okay, thank you.
16 Anything else?
17 MR. RICHARDSON: No, Madam Chairman, we
18 stand on our motion to strike the testimony of Mr.
19 Griswold.
20 COMMISSIONER SMITH: All right, we i II talk
21 to Mr. Kaufmann next, so to use that, the microphones,
22 you i ve probably figured it out, when you want to talk,
23 you need to push the touch so the red light comes on and
24 when you i re done, you need to touch it again so the red
25 light goes off and only the person speaking is heard.
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(20B) 890-5198
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1 Thank you, Mr. Kaufmann.
2 MR. KAUFMANN: Thank you, Madam Chairman.
3 PacifiCorp recognized in the proceeding that NIPPC was
4 very interested in filing testimony itself and,
5 therefore, we wanted the Commission to have the
6 opportuni ty to admit testimony from PacifiCorp in the
7 event it decided to go into an evidentiary phase. Given
8 that the Commission, I believe, has decided that this
9 matter is appropriate for the modified proceeding,
10 PacifiCorp does not oppose the motion to strike.
11 COMMISSIONER SMITH: Okay, then the
12 testimony of Mr. Griswold will not be considered by the
13 Commission. Are there any other preliminary matters to
14 come before the Commission? All right, we have three
15 applicants here, have you chosen who wants to go first,
16 second, third? Mr. Walker.
17 MR. WALKER: Yes, thank you,
18 Madam Chairman.If it please the Commission and counsel,
19 Donovan Walker on behalf of Idaho Power Company and I
20 will go first, followed by Mr. Andrea for Avista and then
21 Mr. Kaufmann for Rocky Mountain Power.I'd like to start
22 off and make a few general statements about such things
23 as regulatory principles and things that are important
24 for this Commission to keep in mind while making such
25 decisions and also do a brief summary of what Idaho Power
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1 has presented in both comments and reply comments and
2 also would like to if there's any allocation of time, I
3 would like to have some opportunity to provide responsive
4 comments following submission of argument by the other
5 parties, if I may.
6 Now, this case is not about whether Idaho
7 Power or anybody else for that matter likes or dislikes
8 PURPA and its requirements or whether anybody likes or
9 dislikes wind or any other renewable generation source.
10 This case from Idaho Power's perspective is about our
11 utility customers and our obligation to provide safe,
12 reliable and fairly-priced energy to our customers and
13 the public. Now, there's been a very healthy dose of
14 comments and submissions to the Commission in this docket
15 and nearly all of those demonstrate some kind of
16 interaction or some kind of conflict with several
17 fundamental principles in public utility regulation.
18 Now, first of all, we all know that a
19 public utility has an obligation to reliably serve load
20 on its system and a utility does so by employing the
21 required principles of least cost planning that are
22 initiated through the integrated resource planning or the
23 IRP process for all utili ties. Also, as we all know,
24 public utili ties are required by federal law, by PURPA,
25 to contract with qualified facilities for the purchase of
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.1 their energy at avoided cost rates; in other words, the
2 cost the utility would pay to otherwise generate or
3 otherwise acquire that energy itself.
4 One other very important requirement of
5 PURPA that's important to keep in mind is that PURPA
6 requires that utility customers be economically
7 indifferent to whether power is purchased from that QF or
8 otherwise acquired by the utility. Now, Idaho Power and
9 the utili ties in this case have made a substantial
10 showing that is supported by Commission Staff and largely
11 unrebutted by the opponents in this case that the current
12 application of the surrogate avoided resource.13 methodology, including the 10 average megawatt cap, has
14 several problems associated with it that have potentially
15 huge ramifications or implications for our customers and
16 for the public, the most severe of which is a dramatic
17 increase in upward pressure on the rates that our
18 customers must pay for power supply costs, a rate which
19 we believe has been shown to be above what would
20 otherwise be considered prudent by the utility or, in
21 other words, beyond the cost of other available lower
22 cost resources.
23 Other significant problems that have been
24 touched upon are the circumvention of the integrated.25 resource planning process, system reliability and
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1 operational issues, as well as what Idaho Power believes
2 to be a fundamental problem with the surrogate avoided
3 resource methodology and its requirement of a continued
4 and unchecked requirement of the utility to continue to
5 acquire additional generation resources regardless of its
6 need for any additional energy or capacity to serve loads
7 on its system.
8 Now, these are all extremely important
9 issues and the filings and pleadings have touched on
10 several others, but as stated in both our comments and
11 our reply, the Company does not expect the Commission to
12 resolve all these orders or issue an order here today
13 that's going to even attempt to resolve all those issues,
14 and indeed, I think as we were reminded by the Chairman
15 at the beginning, the purpose of this proceeding today is
16 for the Commission to decide upon the utilities' motion,
17 preliminarily an interlocutory motion, to reduce the
18 published rate eligibility cap from 10 average megawatts
19 to 100 kilowatts and that that remain in effect while the
20 Commission and the parties can dig into and consider and
21 struggle with and hopefully come to some good workable
22 solutions on these other important issues regarding
23 PURPA, and as such things like that take some time and
24 during the passage of that time there's been a
25 demonstration of irreparable harm that may fall to our
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(208) 890-5l98
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1 customers, we think it very appropriate to grant that
2 request and lower that eligibility cap during the
3 pendency of any further proceedings that are to take
4 place.
5 Now, this potential harm to Idaho Power
6 customers is not just -- is no longer just theoretical in
7 nature. Since the filing of our joint petition in
8 November, November 5th of 2010, nearly all of the then
9 pending proposed PURPA QF proj ects at the Company, that
10 the Company warned of in its petition, have rapidly
11 demanded that the Company enter into published rate
12 avoided cost contracts with them and as a result, there
13 are upwards of 20 pending PURPA contracts at this
14 Commission pending your review at this moment, and as of
15 December 20th, 2010, there was over 840 megawatts of wind
16 QF generation proposed for Idaho Power i s system and
17 that i s with the consideration of a total of 326 megawatts
18 of wind that currently operates on the system and in
19 relation to an additional 219 megawatts in total of
20 non-wind PURPA generation on our system. The magnitude
21 is quite alarming and also alarming is the speed and the
22 amount which is currently pending all at the same time.
23 Now, as far as the Commission i S authority
24 in a case like this, I think there's several undisputed
25 items that are clear to everyone. Reduction of the
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1 published rate eligibility cap clearly does not violate
2 federal law as has been alleged and in fact, doing so
3 would uphold both federal and state law in several ways.
4 It's undisputed that the federal law requires the
5 Commission to make standard rates available for QF
6 proj ects up to 100 kilowatts. It i S also undisputed that
7 beyond that the Commission has very broad discretion in
8 setting avoided cost rates and in implementing FERC rules
9 in its administration of PURPA, and even beyond PURPA,
10 the Commission is entrusted with the obligation and
11 authority to ensure that contracts entered into with
12 public utili ties are not contrary to the public interest.
13 Idaho law clearly states that contracts entered into with
14 public utili ties are entered into subj ect to the reserved
15 authori ty of the state through the Commission to modify
16 those contracts in the public interest.
17 Now, as pointed out by Rocky Mountain
18 Power in their submissions, the Commission's
19 implementation of the 10 average megawatt eligibility cap
20 was a discretionary act of this Commission and as such,
21 that action may be modified with proper notice, citing to
22 Idaho Code 61-624. Rocky Mountain Power's additional
23 arguments regarding the Commission i s procedural schedule
24 does not violate the filed rate doctrine, nor the
25 prohibi tion against retroactive ratemaking Idaho Power
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.1 feels is very sound and very persuasive and we agree
2 with.
3 One of the Commission i s stated areas for
4 comment and investigation for today was also the
5 application of a possible reduction in the eligibility
6 cap to all QF proj ects or non-wind and wind proj ects.
7 Now, Idaho Power obviously and very certainly understands
8 the great magnitude of the proposed -- that the great
9 magnitude of proposed Qf generation, especially in our
10 system, consists of wind; however, the Company maintains
11 that a reduction in the published rate eligibility cap be
12 applicable to all QF generation resources and the reason.13 for that is this: The only real difference in any of our
14 arguments is really that of magnitude.
15 Because all QFs provide energy at light
16 load hours and times when the Company does not need that
17 energy, they all contribute in the same manner to all the
18 price and avoided cost issues that we i ve addressed in our
19 comments and reply comments, and further, one of the main
20 problems, the lack of consideration, any consideration
21 for the utility i s need or in relation to when the QF
22 deli vers the energy to the utility, that doesn i t change
23 whether the QF project is wind or non-wind and it all
24 contributes to the same problem, and we've put forth very.25 clearly and believe very strongly that by utilizing an
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.1 IRP-based methodology even for non-wind PURPA contracts
2 that we can at least start to introduce some concept of
3 value and need into the avoided cost calculation and at
4 least start addressing some of these serious problems
5 that the utili ties are facing operationally and
6 economically for their customers.
7 Idaho Power in its reply comments
8 disclosed that the software provider for its modeling
9 program, AURORA, had advised us that there may be some
10 kind of modeling problems with that software for very
11 small projects under two megawatts in size and we
12 disclosed that in our reply comments, and prior to that.13 time Idaho Power has not been required to run AURORA on
14 projects that small and in fact, we have not run projects
15 smaller than two megawatts through the AURORA modeling,
16 and for several of the reasons that we've outlined in our
17 documents, we had received no requests from anyone to run
18 AURORA pricing for avoided costs for proj ects that low
19 either.
20 However, since the time, since January
21 19th at the time when we filed our reply comments,
22 obviously, we've been working on this issue, we consulted
23 with Avista and found out that Avista routinely runs
24 their AURORA modeling for 100 kilowatt proj ects as part.25 of their IRP process. Also, the Company's analysts also
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1 ran several test modelings at 100 kilowatt levels and the
2 Company is confident that the modeling does result in
3 accurate and usable results for proj ects smaller than two
4 megawatts and that brings me to one other point
5 MR. RICHARDSON: Madam Chairman?
6 COMMISSIONER SMITH: Mr. Richardson.
7 MR. RICHARDSON: Mr. Wal ker i s clients are
8 in direct conflict with the reply comments that the
9 utility filed. To the extent that he's retracting his
10 reply comments, I think he should do that in a manner
11 that allows all the parties an opportunity to review and
12 actually engage in discovery on those. We filed
13 discovery on Idaho Power on their assertion in their
14 reply comments that the AURORA model is flawed for
15 projects less than two megawatts and now the Company is
16 retracting that and we haven't had an opportunity to
17 review any information underscoring or allowing us to
18 understand why the Company is now taking back what it
19 said in its reply comments to the effect that AURORA is
20 flawed and it doesn i t work for proj ects less than two
21 megawatts and the implications that has for projects
22 larger than two megawatts. That's critical information
23 that we need to know and for the Company to retract it at
24 this time is improper.
25 COMMISSIONER SMITH: Mr. Walker.
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1 MR. WALKER: Well, first of all,
2 Madam Commissioner, the Company never did state anywhere
3 that the AURORA modeling was flawed, so we obj ect to that
4 characterization and certainly Mr. Richardson is free to
5 address a simple statement that we've consul ted with
6 Avista and run a test modeling to such effect and
7 addi tionally, Avista has filed a response to that very
8 discovery question that Mr. Richardson has referred to,
9 so he has received some indication of AURORA' s ability to
10 run proj ects at less than two megawatts.
11 MR. RICHARDSON: Madam Chairman, may I
12 respond?
13 COMMISSIONER SMITH: Mr. Richardson, just
14 take a minute. Mr. Walker, when did you become aware and
15 have your discussions with Avista?
16 MR. WALKER: Idaho Power personnel ran
17 test models through the weekend and had discussions with
18 Avista starting on Friday and Monday, I believe.
19 COMMISSIONER SMITH: So last Friday?
MR. WALKER: I believe so.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Thank you,
Madam Chairman.I'll quote from Idaho Power's reply
comments.Proj ects less than two megawatts "are lost in
the rounding to MWs or MWhs, then the base model results
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20
1 could be identical to the modeled results that include
2 the proj ect. The result would -- this would result in an
3 AURORA pricing of zero," for proj ects less than two
4 megawatts and for Idaho Power to claim that their
5 behind-the-scenes consultation with Avista is somehow
6 providing notice to all the parties is preposterous.
7 This is brand new information. It contradicts Idaho
8 Power's reply comments and we haven't had an opportunity
9 to review or analyze the meaning or verify the comments
10 that he's making now that in private consultations with
11 Avista they solved the problem.
12 COMMISSIONER SMITH:I understand your
13 frustration, Mr. Richardson, and I think that you do have
14 the opportunity to check into this, but I also think that
15 Mr. Walker had a duty to advise the Commission if
16 something was incorrect in his comments and they recently
17 discovered it, so we'll take up your response when it's
18 your turn and right now Mr. Walker is going to
19 continue.
21 Madam Chairman.
MR. RICHARDSON: Thank you,
22 MR. WALKER: Thank you, Madam Chairman.
23 Speaking of AURORA, that brings up, you know, this old
24 argument that AURORA is some kind of black box in which.25 to hide work is really not a viable argument anymore in
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.1 this day and age. AURORA is completely transparent and
2 entirely verifiable independently by Commission Staff who
3 does have the program and is very capable and does a very
4 excellent job running and verifying AURORA runs.
5 Addi tionally, AURORA has now long been a
6 part of at least two utilities -- an employed and
7 accepted part of two utilities' IRP process as well as
8 other operational and resource planning processes. It's
9 a sound and -- it's a sound program and in addition to
10 that, it i S part of an existing and approved methodology
11 for determining avoided cost rates and is appropriate for
12 making an avoided cost determination..13 Commissioners, there is an undeniable
14 problem here and Idaho Power is faced with a very rapid
15 and large scale proliferation of QF generation on its
16 system at levels that exceed its entire load, its entire
17 system load, during minimum load hours and exceeds
18 one-third of its entire system load during the Company's
19 highest record system peak hour. The magnitude of the
20 impact of this cannot be denied and has not been denied
21 by anybody.
22 Idaho Power is forced to purchase this
23 power with absolutely no regard to whether it's needed on
24 its system, with absolutely no regard to whether it's.25 called for in the Company's IRP planning process and with
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22 COLLOQUY
.1 no regard to whether there are other lower cost
2 al ternatives available for the Company and its customers.
3 This large scale proliferation of the QF generation comes
4 wi th a large scale price tag and cost to our customers
5 and the public. This cost regardless of whether the
6 generation is needed or not is estimated to exceed $48
7 million annually and you can argue with how that
8 estimation was arrived at and granted, it i S not a precise
9 estimation, but we're talking about a lot of money.
10 We're talking about a huge impact on an annual basis on
11 power supply expenses and we're talking about obliging
12 customers and the Company to continue that for the next.13 20 years.
14 Al though as I stated, it's not expected
15 that we're going to solve any of these problems today and
16 we're not asking you to. I think we are fortunate in
17 that we have an already existing and approved methodology
18 for setting and determining avoided cost rates and that's
19 the IRP-based methodology, and we believe that as
20 demonstrated in our filings as well as the filings of
21 Commission Staff and other utilities that that's been
22 demonstrated to be a very reasonable approach to employ
23 in such a position as this when it's very obvious that
24 everyone needs to step back and take a long look and have.25 a proceeding to investigate these very critical issues of
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20
1 public interest, of great importance to our customers and
2 operationally for the utili ties, and with that, I'll
3 reserve any time I may have for any rebuttal comments.
4 COMMISSIONER SMITH: Commissioner
5 Kempton.
6 COMMISSIONER KEMPTON: Mr. Walker, on page
7 4 of your reply comments, at the bottom of the page,
8 right at the very bottom and going up on the top of page
9 5, you mention that when looking at the 614 megawatts of
10 proposed QF projects that it results in an increased cost
11 to customers estimated at more than $48 million annually
12 to pay for QF generation over current forward energy
13 market rates. How far is that projected into the future
14 to get the $48 million?
15 MR. WALKER: I believe those items were
16 addressed in our initial comments and I can't remember
17 how long the market prices were projected out, but they
18 were not proj ected out for a full 20 years.I can
19 certainly look back to my comments and see.
COMMISSIONER KEMPTON:I'll tell you what,
21 let's come back to that. It can be provided at a later
22 time in today' s meeting. The second question is do you
23 feel that the proposal that Idaho Power has presented in
24 terms of the cap going all the way down to 100 kW is.25 compatible with the 2000 energy plan that's been passed
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1 by the legislature in terms of the intent for the
2 acquisition of renewable resources?
3 MR. WALKER: I think reduction of the cap
4 does absolutely nothing to the intent to acquire
5 renewables.It does nothing to the utility's obligation
6 to continue to negotiate and enter into contracts with
7 proposed QF proj ects. What it does do is change the
8 methodology by which the avoided cost for those proj ects
9 is calculated.
10 COMMISSIONER KEMPTON: So that would bring
11 up the issue of how transparent the AURORA process is and
12 so I would like to ask how you make the AURORA process
13 transparent in terms of the variables that you i re using
14 and how that i s made transparent, again, to customers and
15 that would include developers and the general public.
16 MR. WALKER: Well, I think, you know, as I
17 stated, one check on the system is that Staff is able to
18 independently run and verify any numbers or calculations
19 or runs through AURORA and it can have the same level of
20 transparency that it has through the Company's IRP
21 processes in which AURORA is the basis for all of the
22 analysis and evaluation of the resource portfolios and to
23 that extent, I don't see -- you know, it's been around
24.25
for awhile.It's no longer the great mystery. It is
true that it's a proprietary software that must be
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1 purchased and licensed in order to run and to work the
2 actual calculations, but people have been comfortable
3 enough in working with that and it's an accepted part of
4 resource planning and that's really -- I think it works
5 well because, you know, this is an IRP-based avoided cost
6 methodology and it uses the same tool that we use in the
7 IRP process to introduce some of these concepts, such as
8 need and value of the energy of when it's provided and
9 when it's useful to the utility, and I think it's
10 fortunate that that's an already existing methodology to
11 utilize for avoided cost. It's not like it's a brand new
12 method being employed for the first in PURPA proj ects.
13 It exists and it's been acceptable to the Commission and
14 to the parties and the utili ties to exist in that fashion
15 and we really don i t see this as that big of a change.
16 COMMISSIONER KEMPTON: Okay.
17 COMMISSIONER SMITH: Thank you, Mr.
18 Walker. Mr. Andrea.
19 MR. ANDREA: Yes, good morning again,
20 Madam Chair, Commissioners. I'm going to thank the
21 Commission for the time this morning to discuss this very
22 important issue. I'm not going to restate the things Mr.
23 Walker has stated or try not to. He covered a lot of the
24 issues and points that we would also agree with, so I'll
25 try and keep it short and hopefully reserve a little bit
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26 COLLOQUY
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1 of time for rebuttal at the end.
2 As Mr. Walker said, I do want to put a
3 point on this, this is not a request for a moratorium.
4 The issue is not whether the utilities have an obligation
5 to purchase outputs from the QFs. The issue is what is
6 the appropriate rate for them to purchase that output for
7 from the QF. As Mr. Walker said, this is about the
8 customers and what rate the customers are ultimately
9 going to pay for this QF power.
10 Avista agrees that the published avoided
11 cost rate makes practical sense for truly small QFs, QFs
12 smaller than 100 kW. The problem as Staff recognized in
13 their comments and I think has become apparent is that
14 large QFs, not just those truly small QFs, are taking
15 advantage of that avoided cost rate and becoming quite
16 imaginati ve at coming up with ways to do that.
17 Just kind of for context, I want to talk a
18 little bit about the region and the neighboring states
19 have all struggled with various PURPA issues and come up
20 wi th various PURPA schemes. They have to be looked at
21 holistically. None of those schemes would work in Idaho
22 if the rate is different, so for example, Oregon has a
23 physical separation requirement and a lower rate and that
24 seems to have worked. Washington limits the size of the
25 QF and also limits the term of the contract, I think, to
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27 COLLOQUY
.1 fi ve years if you're going to take advantage of the
2 published avoided cost rate.
3 The reason I think this is important for
4 context is Avista is seeing interest from developers in
5 neighboring states who want to deliver their output to
6 Avista in Idaho. A really good example, we have two
7 complaints filed against us right now by developers in
8 Oregon, neighboring developers in Oregon, who are willing
9 to pay as much as two wheels to get their output to
¡10 Avista in Idaho and that's because with the 10 average
11 megawatt cap and the rate that currently exists under the
12 published avoided cost rate, it provides that economic.13 incentive for them to do that, so in short, Avista asks
14 that the Commission take immediate action to reduce the
15 eligibili ty cap to 100 kW and the Commission make that
16 reduction permanent.
17 Again, and this really, truly bears
18 emphasis, this is not a request for a moratorium. Avista
19 will still continue to have a PURPA obligation to
20 purchase the output and will purchase it at a rate that
21 more closely reflects our true avoided cost. The IRP
22 rate methodology works fine to do that, and I want to
23 take just a second to respond to the comments by NIPPC
24 that the IRP methodology is flawed or is illegal..25 The IRP methodology, and I think Mr.
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.1 Wal ker covered this quite well, it's not new.It 1 s
2 exactly how we determine how to acquire new resources
3 today for ourselves. To imply that it's flawed is to
4 imply that the IRPs themselves are flawed.In the case
5 of Avista, we've been using that IRP methodology since
6 1989.It's not flawed and it's not new and we're
7 commi tted to make it as transparent as possible for the
8 customers, for the Commission and for the developers.
9 NIPPC also suggests that it may be illegal
10 because it does not consider all of the FERC factors and
11 I think NIPPC overstates to some degree in their comments
.12
13
14
the requirement.It's not an absolute obligation. It's
an obligation to consider those requirements to the
extent practical and I can confidently represent to this
15 Commission today that Avista' s IRP methodology considers
16 each and everyone of those factors, so any suggestion
17 that the IRP methodology is illegal on that basis is
18 completely without merit.
19 I do want to address just really quickly
20 Idaho Power's concerns about the AURORA program working
21 for two megawatts or less. As Mr. Walker noted, Idaho
22 Power has worked with Avista over the past week or so to
23 work on that issue and I think they've come to the
24 conclusion that they're comfortable that it does in fact.25 work. Avista has always been comfortable that it does in
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29 COLLOQUY
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1 fact work. We have substantial experience with the
2 AURORA model. Owl modelers have been using it for quite
3 some time and we routinely use it for proj ects of 100 kW
4 in our IRP process and it produces very valid results.
5 I also want to address concerns that the
6 IRP methodology may be complex or a black box. As I
7 said, we're committed to making that process as
8 transparent as possible. To be sure, there are license
9 requirements. We can't just hand the models over to
10 anybody even if we would like to, but we are willing to
11 take whatever steps we can wi thin the limits of our
12 obligation to make the process transparent, and those
13 steps can include, among others, we i ve offered to
14 developers in the past that they can come up and they can
15 watch us run the model. We hold that open to developers.
16 Developers can at a very minimal cost
17 retain their own consultants who have those licenses and
18 who are experienced with those models to verify the
19 resul ts . Given the intense capital costs of even small
20 proj ects, the cost of such a consultant would be de
21 minimis in relation to the cost of even a one megawatt
22 project.
23 Also, Avista, as we noted in our comments,
24 encouraged the Commission Staff's participation. We
25 obviously don't want to create a burden or additional
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30 COLLOQUY
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1 task for Commission Staff, but to the extent the
2 Commission Staff is interested and wants to make sure
3 that the models are transparent, we encourage their
4 participation, and if a developer wants Staff there and
5 Staff is willing to be there or Staff is willing to run
6 the models, as Mr. Walker noted, they 1 re quite adept at
7 doing so and we encourage their participation.
8 Again, Avista appreciates the Commission IS
9 time on this issue. We believe that reducing the
10 eligibility cap to 100 kW is the most practical,
11 simplest, most easily implemented and enforced solution
12 to the issues that we're faced. It will allow the
13 utili ties to continue to acquire QF power at a rate that
14 accurately reflects their true avoided cost, and I'll
15 just suggest in passing that the 100 kW solution also is
16 likely to resolve many of the other issues that we're
17 facing with PURPA, including the environmental attribute
18 ownership issue and the wind integration charge issue.
19 It's not to say it's going to solve all of
20 the problems, but it provides an elegant solution to some
21 of those problems, because those issues are automatically
22 considered in the IRP methodology process in developing
23 that rate and i t solves those problems.
24 Again, thank you for your time and I'll
25 reserve some time for questions and hopefully for some
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31 COLLOQUY
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1 rebut tal. Thank you.
2 COMMISSIONER SMITH: Commissioner
3 Kempton.
4 COMMISSIONER KEMPTON: Mr. Andrea, what's
5 the PURPA cap in Washington?
6 MR. ANDREA: I believe they just increased
7 it to five megawatts with a five-year maximum contract
8 term.
9 COMMISSIONER KEMPTON: And in the past
10 you've been working at two megawatts?
11 MR. ANDREA: It's been one megawatt up
12 until about a month or two ago.
13 COMMISSIONER KEMPTON: And you used AURORA
14 in the range of one megawatt to determine avoided cost?
15 MR. ANDREA: Just one second. Yes, it was
16 an AURORA run for the first five years based on the
17 market price, so it was used for that.
18 COMMISSIONER SMITH: Mr. Kaufmann.
19 MR. KAUFMANN: Thank you, Madam Chairman,
20 and thank you, Commissioners Redford and Kempton. 11m
21 here to speak today to the issue of whether the
22 Commission should reduce the 10 average megawatt
23 eligibility cap to 10 megawatts or, Ilm sorry, to 100
24 kilowatts or another intermediate value. Specifically,
25 I'LL be addressing in the next 12 minutes the three
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32 COLLOQUY
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1 points the Commission asked the utili ties to address in
2 Order 32131, starting first with issue 3, the
3 consequences of dividing large QF wind proj ects into 10
4 average megawatt sub proj ects in order to qualify for
5 published rates.
6 I will refer to this in my talk as
7 disaggregation and I'd like to make a few observations
8 about disaggregation at the start. From the air and from
9 the ground a proj ect that has been disaggregated looks a
10 lot like a large wind QF project. Except for additional
11 meters, the differences are almost purely legal. Instead
12 of one power purchase agreement, a disaggregated proj ect
13 will have several power purchase agreements.Instead of
14 one QF self-certification, there will be one for each QF
15 that seeks a contract; however, disaggregated projects
16 share interconnection facilities. They're negotiated
17 together on an all or none basis. They're in my
18 experience permitted together, financed, constructed, and
19 commissioned together. In essence, they are one proj ect.
20 The principal and possibly only benefit of
21 disaggregation is the eligibility of sub projects for
22 published avoided cost prices. This is evidenced to
23 PacifiCorp by the fact that all of its disaggregated QF
24 facilities currently under contract have a maximum
25 expected monthly average generation of approximately 10
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33 COLLOQUY
.1 average megawatts.If the Commission by any means makes
2 disaggregated projects ineligible for published prices,
3 the phenomenon of disaggregation in Idaho is likely to
4 disappear.
5 What are the consequences of
6 disaggregation? Well, those consequences include a
7 dramatic increase in total QF output purchased by
8 PacifiCorp in Idaho at the published avoided cost rate.
9 From 2005 to 2010, total QF capacity under contract with
10 PacifiCorp in Idaho increased from 6.8 to 8.3 megawatts,
11 but in 2010 alone, PacifiCorp added 177 megawatts of new
12 QF wind capacity. The increase was caused by two.13 disaggregated wind projects which amounted to seven
14 separate 10 average megawatt QFs, each of which received
15 the 20-year PPA at the published avoided cost price.
16 PacifiCorp has compared this to the
17 modeled avoided cost using its IRP methodology and
18 estimates that the net present value difference in cost
19 is greater than $100 million . Ultimately, these
20 obligations will be borne by PacifiCorp' s ratepayers as
21 power costs recovered through retail rates.
22 Disaggregation has become the preferred method for large
23 wind proj ects in Idaho to develop compared to the IRP
24 methodology or RFP bids, RFP's from utilities for bid.251 prices.
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34 COLLOQUY
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1 PacifiCorp has purchased only one Idaho
2 wind project through the RFP process and that was in 2005
3 and it has not contracted with any QFs using the IRP
4 methodology. Disaggregation has no theoretical upper
5 limit. To date, welve seen a 133 megawatt project;
6 however, much larger proj ects are possible and state
7 boundaries are no barrier. As you know, PURPA entitles
8 an out-of-state QF to wheel its power to Idaho and
9 recei ve the published avoided cost rate if it's otherwise
10 eligible to do so.In sum, for any QF technology that
11 may be developed in increments of less than 10 average
12 megawatts, the 10 average megawatt eligibility cap in its
13 current form is little more than a speed bump and a minor
14 one at that.
15 Next, I'LL speak to issue 1 posed by the
16 Commission, the advisability of reducing the published
17 avoided cost eligibility cap. I note that in 2005 when
18 this Commission adopted the 10 average megawatt cap, its
19 stated goals were to encourage development by small QFs
20 that otherwise lacked the money and expertise to
21 negotiate terms of a power purchase agreement with the
22 utilities.It's self-evident that whether or not this
23 goal is being accomplished for small utilities, a great
24 beneficiary of this rule are large sophisticated
25 developers.
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35 COLLOQUY
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1 PacifiCorp's two disaggregated Idaho wind
2 proj ects were developed by Windlin and Summit Power and
3 neither could fairly be called a small QF lacking money
4 or expertise to negotiate terms of a PPA. For large QF
5 proj ects, PacifiCorp believes the published avoided cost
6 rates are too high. Those QFs because they're able to
7 qualify for these published avoided cost rates are not
8 willing to bid into RFP' s at a price lower than those
9 rates. So long as they may obtain the published avoided
10 cost rate, it has no incentive and, therefore, the
11 published rate acts as a floor to any RFP published by
12 the utility and similarly, if a large QF can qualify for
13 published rates, it will never opt to sign for
14 IRP-calculated rates, unless, of course, those rates do
15 happen to be higher than the published rates.
16 In effect, the large QFs have an option
17 and this option is valuable and that value comes at the
18 expense of ratepayers. PacifiCorp has witnessed this
19 behavior in 2010. Cedar Creek Wind originally bid into
20 PacifiCorp's most recent RFP which was not 2010, but its
21 most recent one in '09; however, it was not competi ti ve
22 on a price basis and was not selected. Cedar Creek then
23 requested IRP pricing for a single large QF at the same
24 site that it had bid in the RFP.
25 PacifiCorp calculated a levelized avoided
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36 COLLOQUY
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1 cost using the IRP methodology of about $57.00 a
2 megawatt-hour. Cedar Creek rej ected this as too low and
3 opted to disaggregate its proj ect so that it could
4 recei ve the published avoided cost rate which accounted
5 for the wind integration charges of about $76.00 on a
6 levelized basis. So long as the published avoided cost
7 price is a floor for large energy proj ects, it may also
8 be inflating the IOU's cost to procure new capacity via
9 an RFP process.
10 All of the reasons above suggests that the
11 current cap is not working and careful reassessment is
12 warranted.In the meantime, conditions do warrant a
13 temporary reduction of the cap to protect ratepayers from
14 possible long-term harm. An immediate reduction is
15 justified because without action, QF development in 2011
16 could exceed what was experienced in 2010. Four weeks
17 into 2011, PacifiCorp has over 230 megawatts of QFs in
18 its published avoided cost rate contract queue, including
19 91 megawatts who contacted PacifiCorp before December
20 14th have not yet executed contracts and are requesting
21 grandfathered treatment. There is still time for new
22 projects potentially to apply to PacifiCorp today and
23 become eligible for a PPA before the Commission reaches a
24 final decision on the utilities' petition.
25 Now, I understand there are good policies
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37 COLLOQUY
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1 for -- policy reasons for having predictability in rates,
2 but I do want to reiterate from my brief that reducing
3 the cap would not violate the rights of QF developers,
4 because QFs do not have a protected or due process
5 interest in a particular avoided cost rate until they
6 have either signed a contract or this Commission has
7 determined in a meritorious complaint that the utility
8 has wrongly denied them a contract, and I also reiterate
9 from my reply brief that the Commission may change the 10
10 average megawatt eligibility cap at any time upon proper
11 notice with or without an evidentiary hearing. The
12 Commission i s notice in this case was adequate and I might
13 add that all of the parties had constructive, if not
14 actual, notice of the IOUs' petition at the time it was
15 filed.
16 Finally, today I'LL address item 2 of the
17 Commission's list, the appropriateness of exempting
18 non-wind QF proj ects from the reduced eligibility cap,
19 should the cap apply only to QF wind proj ects or should
20 it apply to all QF proj ects. Exempting non-wind QFs from
21 the reduced cap would not eliminate all ris k to
22 ratepayers.PacifiCorp knows of one specific instance
23 where a developer is seeking to divide its planned
24 municipal waste QF facility into two projects in order to
25 be -- that both of them could be eligible for published
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38 COLLOQUY
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1 prices, and it's also a fact that the solar proj ects that
2 are comprised of modular BP units or other modular units
3 may be susceptible to disaggregation such as wind
4 proj ects and that they would have the same financial
5 incentives that wind projects have to do so; therefore,
6 PacifiCorp believes it's in the best interests of
7 ratepayers that the cap apply to all types of QFs.
8 PacifiCorp also believes that reducing the
9 cap of wind proj ects only may be legally permissible, but
10 only if done correctly and this is not in my reply brief,
11 but I'd like to call the Commission's attention to the
12 following Order denying rehearing which was published by
13 FERC on January 20th, 2011, the day after PacifiCorp
14 submitted its reply comments. The citation is 134 FERC
15 ~ 61,044. This is the California proceeding in which the
16 utilities and the commission have sought clarification
17 from FERC on the legality of feed-in tariffs, and in that
18 Order denying rehearing, FERC appears to be saying that
19 it's laid out a road map by which utility commissions,
20 state commissions under PURPA may have tiered avoided
21 cost rates, but that road map appears to contemplate that
22 the commission first set a procurement mandate for a
23 specific type of resource, i.e., combined heat and power
24 in that case, we want 50 megawatts by 2015, and then
25 determine the avoided cost based on all the generators
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39 COLLOQUY
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1 capable of bidding into that particular niche.
2 Now, I don't think that that road map is
3 the one that the Commission currently has and I will only
4 say at this juncture that I believe that applying the cap
5 to wind only involves some legal risk that the wind
6 parties who are aggrieved by that decision would appeal
7 this decision and if successful nullify the Commission's
8 remedy, and in any event, I believe there is uncertainty
9 regarding the adequacy of that remedy and I think
10 uncertainty is something that we all hope to avoid.
11 Finally, I would stress, and this was in
12 my reply brief, that a cap reduction should clearly apply
13 equally to non-firm and firm QFs. Firm QFs typically
14 PacifiCorp's experience are ones that are off-system and
15 deliver via a firm schedule. I did address that in my
16 brief, but I point out if we don't do that, then Idaho's
17 wind proj ects are free to wheel their power to PacifiCorp
18 and PacifiCorp i s wind projects can wheel to Avista and so
19 on, so I think it's imperative that a reduction in the
20 cap has to be applied to non-firm or off-system QFs as
21 welL.
22 For all the reasons above, PacifiCorp
23 joins Idaho Power and Avista in requesting the Commission
24 to immediately reduce the cap to 100 kilowatts for all
25 types of QFs while it revisits its methodology to
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1 determine whether the published avoided cost rates are
2 too high and whether the existing 10 average megawatt
3 eligibility cap should be reduced on a long-term basis.
4 If I may, I'd like to reserve time for rebuttal at the
5 end. This concludes my remarks and thank you for your
6 time and the opportunity to be here today.
7 COMMISSIONER SMITH: Thank you, Mr.
8 Kaufmann. Commissioner Kempton.
9 COMMISSIONER KEMPTON: Mr. Kaufmann, I
10 assume that the waste plant you were talking about must
11 be in Oregon.I f not, I can't see an advantage to
12 subdi viding or disaggregating something that would be a
13 total, as I understood your testimony, about three
14 megawatts.It wouldn't apply in Idaho, and Washington is
15 now moving to five, but be that as it may, what is the
16 cap in Oregon?
17 MR. KAUFMANN: Thank you, Your Honor. The
18 cap in Oregon is 10 megawatts nameplate. The proj ect I
19 was referring to was an Idaho proj ect and it was a 17
20 megawatt average, approximately.
21
22
COMMISSIONER KEMPTON: Average megawatts?
MR. KAUFMANN: Sorry, 17 nameplate, but
23 being a waste facility, it had a very high capacity
24 factor above 10 average megawatts.
25 COMMISSIONER KEMPTON:I'm sorry, I
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.1 thought that when you briefed this that you were much
2 lower than that in the numbers that you gave, but I could
3 be wrong.
4 MR. KAUFMANN: Your Honor, I believe it
5 said 17, but I'm sorry, I can't put my finger on it right
6 at this moment.
7 COMMISSIONER KEMPTON: Okay, don't waste
8 time on this. The reason I asked the question is because
9 I thought we were disaggregating from a very low level
10 when you were making your point around the 100 kW rather
11 than 10 megawatts, so that's all the questions I have on
12 that..13
14
COMMISSIONER SMITH: Mr. Kaufmann, I have
a question. You addressed the legal risk of exempting
15 non-wind, is there any legal risk with trying to do a
16 disaggregation or preventing disaggregation?
17 MR. KAUFMANN: Madam Chairman, I believe
18 that the avoided cost may be different for a small
19 proj ect than for a large proj ect and I believe that the
20 Commission may therefore have different avoided costs and
21 I believe that disaggregated projects are in essence
22 large proj ects, that it's legally permissible to
23 differentiate on that basis. I think many states have
24 had standard offer contracts with eligibility criteria.25 that are based on size.
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1 COMMISSIONER SMITH: But if they
2 disaggregate so they come within your size requirement,
3 how do you get at the fact that they should have been or
4 could have been a larger proj ect and they just
5 dis aggregated in order to take advantage of a published
6 rate?
7 MR. KAUFMANN: Well, there are different
8 approaches. In Oregon there is a partial stipulation
9 that parties to a general rulemaking agreed to which
10 incorporates a five-mile separation rule and I believe
11 that has functioned reasonably well in Oregon.
12 Alternatively, if the cap is reduced to a number that is
13 sufficiently low, then the feasibility of disaggregating
14 a proj ect is greatly reduced. Most of the wind turbine
15 projects that we have seen have individual turbine
16 nameplate capacities of 1.8 megawatts and above, so
17 clearly, a 1.8 megawatt turbine can i t be disaggregated to
18 anything smaller than that, and if there's a one-mile
19 separation rule that the Commission would adopt, then I
20 believe the disaggregated proj ects that PacifiCorp
21 contracted with in 2010 would not have qualified for the
22 published rates.
23 COMMISSIONER SMITH: So you believe that
24 mileage requirement is legally sustainable, no risk
25 there?
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20
21
1 MR. KAUFMANN: Madam Chairman, I think
2 that the FERC floor for standard contracts is 100
3 kilowatts, so I believe if the Commission in its
4 discretion wants to have a tier above that where QFs can
5 be eligible for standard prices that it could do so and
6 it could do it on conditions as well, such as the
7 one-mile rule.
8 COMMISSIONER SMITH: I see what you're
9 saying, so have you looked at the comments of the Idaho
10 Conservation League and the Renewable Northwest Project
11 and their Attachment 1?
12 MR. KAUFMANN: Yes, I have.
13 COMMISSIONER SMITH: So is that an
14 approach that you find sustainable?
15 MR. KAUFMANN: I think the approach can be
16 workable; however, I do have some concerns about this
17 particular formulation.
18 COMMISSIONER SMITH: Okay, well, we won i t
19 go into detail on that.
MR. KAUFMANN: Okay.
COMMISSIONER SMITH: I was just curious of
22 your initial reaction, but I think I understand your
23 position. Thank you.
24
25
Mr. Richardson.
MR. RICHARDSON: Thank you,
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44 COLLOQUY
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1 Madam Chairman. I think I first want to address the
2 fundamental premise for this docket and that 1 s the
3 assertion that Idaho Power is being overwhelmed with wind
4 proj ects and I'm going to as k the Commission to take
5 official notice of a page out of Idaho Power's wind
6 integration study that was filed with this Commission, a
7 docket that I will cite when I get back to my desk
8 here.
9 (Mr. Richardson distributing documents.)
10 MR. JEPSON: I can't hear.
11 COMMISSIONER SMITH: Mr. Richardson is
12 passing out a document that he will identify when he gets
13
14
back to his microphone.
MR. RICHARDSON: Madam Chairman, this is
15 document page 35 out of the Internux Idaho Power 2007
16 wind study filed in Case No. IPC-E-07-03 in February of
17 2007. What this suggests is that there is no evidence
18 that the utili ties can't handle the contracts pending
19 with them; therefore, the Commission is not able to
20 answer the question of the advisability of lowering the
21 cap. In fact, from what we have been able to learn,
22 there is no problem in Idaho Power's claim that the sky
23 is falling is wholly misplaced. Despite Idaho Power's
24 statements in the joint motion regarding 1,100 megawatts
25 of wind being near Idaho Power's minimum loads, Idaho
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1 Power's own 2007 wind integration study concluded that
2 even at 1,200 megawatts of wind on line, the Company
3 would only reach 80 percent of loads given expected wind
4 output, simultaneous expected wind output, in Idaho
5 Power's load forecasts, and it would only reach 80
6 percent for a few hours in the year.
7 In addition, all of Idaho Power's
8 contracts provide a provision that allows Idaho Power to
9 curtail deliveries in the event there is a reliability
10 issue on Idaho Power's system. Finally, Idaho Power has
11 failed to update its wind integration study which was
12 supposed to have been done in 2010 according to Idaho
13 Power's own 2009 integrated resource plan, and consistent
14 with your instructions in Order No. 30488 that "expect
15 annual review by the Company and proposed adjustments in
16 wind integration when warranted."
17 Instead of this bludgeon type of filing,
18 Idaho Power was supposed to be constantly monitoring the
19 si tuation and was supposed to have had a wind integration
20 study update prepared and filed last year.Idaho Power
21 will soon have Langley Gulch on line and never in its
22 wind integration studies did they consider the balancing
23 effects of Langley Gulch or its other natural gas-fired
24 plants for integrating wind. The time for the updated
25 wind study has come and passed, but Idaho Power has never
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1 filed such a study. If there is a problem, it is of
2 Idaho Power's own making and the industry should not be
3 forced to suffer due to its failure to comply with your
4 directives.
5 I want to talk about disaggregation for a
6 minute, but before I do that, I want to explain to you
7 why we believe the integration resource plan methodology
8 is not only flawed, but if you reduce the eligibility cap
9 to 100 kW, it's illegal. Implementation of the IRP
10 methodology in the manner recommended by the utili ties
11 and the Commission Staff will yield an estimate of
12 variable running costs for the utility, not the utility's
13 avoided cost. The models used by the utili ties, AURORA,
14 GRID or whatever, are commonly known as power supply
15 models and they produce estimates of the variable running
16 costs to the utility.
17 The power supply models are run first
18 wi thout and then including at zero cost the particular
19 generating facility being examined. The differing cost
20 between the two runs are divided by the facility's
21 expected output to yield a per megawatt-hour value. This
22 method produces the utility's variable running costs. In
23 order to determine the full avoided cost, the capital
24 components of the facility must be included. The values
25 advocated by the utilities and the Commission Staff do
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1 not produce the full loaf of what PURPA requires in
2 estimating a utility's full avoided cost rate.
3 We're prepared to call Dr. Reading who has
4 worked with AURORA. He knows the model. He's worked
5 with power supply models. He's written power supply
6 models, and he can explain to you in great detail why the
7 IRP method doesn't estimate avoided cost rates. It just
8 simply estimates the utility's running costs which is
9 very different from what the avoided cost rate is
10 supposed to measure, which is the measure of the next
11 resource the utility is bringing on line, which is what
12 this Commission has adequately done with the proxy
13 method, the surrogate avoided resource.
14 In fact, in our comments we point out that
15 when you run Langley Gulch through Idaho Power's
16 integration resource plan methodology, the IRP, run it
17 through their AURORA as if it were a PURPA proj ect, it
18 values Langley Gulch at $75.00 a megawatt-hour; whereas,
19 Langley Gulch is being put into rate base at $126 a
20 megawatt-hour. That delta suggests that the IRP
21 methodology is not accurately estimating the marginal
22 cost of resources and that delta you could fairly say
23 represents the capacity value of the Langley Gulch being
24 dispatchable, because when you run the Langley Gulch
25 through the IRP methodology, you run it through at 90
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1 percent capacity factor.
2 In reality, Langley Gulch is going to be
3 run more like a 55, 60 percent capacity factor, so if the
4 ratepayers were buying Langley Gulch as a PURPA project,
5 they would be paying $75.00 a megawatt-hour and they
6 would have the difference between it and the rate base
7 amount of $126, $50.00 a megawatt-hour, to dispose of
8 surplus Langley Gulch production. That's a stark
9 illustration of the flaw in the integrated resource plan
10 methodology for setting avoided cost rates, which gets me
11 to the point of disaggregation.
12 Disaggregation is irrelevant and a
13 non-issue, because if the avoided cost rates are
14 accurately set, the rates for an IRP methodology avoided
15 cost proj ect would be essentially the same as the rates
16 for a non- IRP methodology avoided cost proj ect. The
17 consequences of disaggregation mean that the utility
18 should actually comply with the letter and spirit of
19 PURPA. By using the IRP methodology, they're avoiding
20 having to pay full avoided cost rates for proj ects larger
21 than 10 megawatts.
22 It i S not gaming the system to break a
23 proj ect up into multiple parts. It i S actually taking
24 advantage of the federal law which requires you to
25 encourage the development of renewable and QF proj ects,
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1 and by setting the avoided cost rate accurately, you
2 don't run into this disaggregation issue.I mean, people
3 talk about it like it's some evil thing, but what it's
4 actually doing is complying with the law.It's a good
5 thing.
6 Another fundamental flaw with this case is
7 that we're not talking about the real issue. The real
8 issue here, Mr. Kaufmann referenced the rates are too
9 high, Mr. Andrea said the issue is what is the
10 appropriate rate. If that's the question, let's go back
11 to March 16 of this year when you just set the avoided
12 cost rates. Maybe this is more of a collateral attack on
13 your March 16 Order setting the avoided cost rates as
14 opposed to a question of disaggregation or eligibility
15 cap. The utili ties, their opening j oint comments didn't
16 mention the rates were too high necessarily. They said
17 the costs to the ratepayers are excessive, but in their
18 reply comments, they got to the heart of the matter which
19 is really what their issue is which is they think the
20 avoided cost rates are too high.
21 Well, that mayor may not be true on your
22 proxy method.I don't know if the natural gas price
23 needs to be updated or whatever, but the issue is, and
24 both counsel for Avista and Rocky Mountain Power said it
25 straight out this morning, the rates are too high.
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13
14
15
16
1 That's their issue. It's not the eligibility cap. It's
2 not disaggregation which is a fiction that's created
3 because of the disparity between your accurately set
4 proxy rate and the wholly inaccurate IRP methodology.
5 No developer is going to go in for the IRP
6 methodology knowing that it sets the avoided cost rate
7 under actual avoided cost rates if they're able to take
8 advantage of the true avoided cost rate which you
9 determined in March. You said the avoided cost rate is X
10 and here's our eligibility cap. If you're over X, you do
11 the integrated resource planning methodology, but because
12 the industry has gotten used to, if you will, being able
to sell at the true avoided cost rate for proj ects under
10 average megawatts, the integrated resource plan
methodology has never been vetted.It 1 S never really
been litigated.It's untested. It works fine for
17 setting resource plans, but it's never been used in any
18 kind of consistent way for setting the avoided cost rates
19 and that's extremely well illustrated this morning when
20 we heard that Avista and Idaho Power got each other
21 comfortable with the IRP methodology for proj ects under
22 two megawatts.
23 Well, they didn't get the industry
24 comfortable. We don't know what they talked about. We
25 don't know what flaws Idaho Power identified. They said
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51 COLLOQUY
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1 they were notified by the software developer that the IRP
2 methodology, the AURORA model, doesn't work. Then over
3 the weekends Avista calls Idaho Power and says, oh, it
4 really does work and now we hear it does. That raises
5 serious questions in my mind about whether or not you can
6 rely given the flaws I just mentioned on how the IRP
7 methodology is inherently designed to underestimate
8 avoided cost rates, now we know it can't even see
9 proj ects under two megawatts and that really raises
10 serious questions in my mind. If I'm a three megawatt
11 project, how much of my three can't it see? If I'm a 10
12 megawatt project, can it not see 20 percent of my
13 proj ect? I don't know. I don't have $50,000 and Don
14 Reading for three weeks to go into the IRP methodology
15 and verify it.
16 The utili ties are using the sky is falling
17 metaphor that we have new proj ects coming on in alarming
18 magnitudes, it's undeniable, it's a problem, but their
19 own wind integration study shows that it's not a problem
20 and we don't know what the addition of all this natural
21 gas-fired capability on Idaho Power's system has to allow
22 it to integrate wind projects, because the wind
23 integration study assumed there was no natural gas and
24 natural gas peakers, as I understand it, not being an
25 engineer, but I understand natural gas peaker plants are
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1 uniquely situated to integrate variable generation
2 projects like wind, and then we point out in our comments
3 that the ability of backing off the coal plants, which is
4 identified by Idaho Power as a problem, is really a
5 benefit, particularly given the looming EPA regulations
6 on carbon emissions as a pollutant which is happening and
7 the rules will be out and final in July of this year, so
8 backing off coal is not a bad thing and the fact that
9 coal is cheap is a short- lived fiction because coal with
10 the carbon regulations coming down the pike, we
11 identified, like, 12 rulemakings, environmental
12 rulemakings, that all are going to increase the cost of
13 coal.It's a real risk that these renewable energy
14 proj ects will mitigate in real time and provide benefit
15 and value to the utili ties well over and above the
16 avoided cost rates.
17 Then I want to just briefly touch on the
18 filed rate doctrine. At least one of the utilities in
19 response to discovery from NIPPC responded that there's a
20 question mark as to whether or not there are published
21 rates for projects over 100 kW right now today even
22 though you have not issued an order declaring that those
23 rates are not available, and the filed rate doctrine
24 provides for parties to rely on this Commission's orders
25 and pronouncements until those orders and pronouncements
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1 are changed pursuant to a public process with opportunity
2 to be heard, and the utili ties are now filing signed
3 contracts with you that they have signed in which they're
4 as king you actually to rej ect the contract, and I don't
5 want to get into an argument about good faith and fair
6 dealing and contract law, but what the utili ties are
7 doing are essentially creating a de facto moratorium on
8 new projects and actually asking you to reject a contract
9 that they signed.
10 That's unconscionable in my mind, so
11 projects that have been in the works, spending money,
12 negotiating with the utili ties in reliance on your
13 published orders should not be disadvantaged and should
14 not have their contracts rej ected by this Commission
15 because the utilities are actually asking you to reject
16 them after they signed them, and I guess the ultimate
17 disconnect in this case is that the utili ties talk about
18 buying PURPA power like it i S a bad thing. Buying PURPA
19 power is nothing more than complying with a federal law
20 that requires this Commission to encourage the
21 development of renewable energy and other types of QF
22 proj ects and to thwart the natural inclination well
23 documented of the utili ties to avoid doing so.
24 Thank you, Madam Chairman.
25 COMMISSIONER SMITH: Thank you, Mr.
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54 COLLOQUY
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1 Richardson. Are there questions?
2 Mr. Williams.
3 MR. WILLIAMS: Madam Chairman, thank you
4 for this opportunity. I just have one point that I'd
5 like to respond to and it has to do with PacifiCorp and
6 the utility's default proposal that if you -- regarding
7 disaggregation of proj ects that if you -- that these
8 projects should have to negotiate a modeled integrated
9 resource plan rate and I think there's a difference in
10 the models that Avista and Idaho Power used, which is the
11 AURORA model and that the Commission has the ability to
12 run that model, versus the PacifiCorp GRID model, that
13 the Commission and none of the parties have the ability
14 really to challenge that model or at least effectively
15 challenge the model.
16 PacifiCorp continues to refer to the Cedar
17 Creek Wind proj ect as the example of how disaggregation
18 has been abused, but if you were to review the affidavit
19 of Cedar Creek Wind filed in their contract approval
20 cases yesterday, it tells a little bit different story
21 and it tells a story of attempted negotiations with
22 PacifiCorp over the course since 2008 through 2010 and in
23 fact, they were short listed initially on one of their
24 bid proj ects at a rate that at that point was lower than
25 the filed avoided cost rate, but higher than today' s
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55 COLLOQUY
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1 avoided cost rate and then when they failed in that
2 attempt, they approached PacifiCorp and spent about four
3 to five months attempting to negotiate a rate for a 78
4 megawatt PURPA project and it was represented that that
5 rate calculation would occur in approximately two to four
6 weeks and in fact took more than three months to produce
7 those results, and when those results were produced, it
8 produced a first year -average rate of about $37.00 a
9 megawatt-hour, and it i s just interesting to contrast the
10 AURORA model's calculation of a similar 78 megawatt wind
11 project for the Rockland project that priced out at about
12 almost $59.00 a megawatt-hour.
13 The developer had no realistic means of
14 challenging the validity of that model and it appears
15 especially ironic when you compare Idaho Power and
16 PacifiCorp with PacifiCorp just filing at the Utah and
17 Oregon commissions for approval of large-scaled gas
18 proj ects. The cost information of that is proprietary,
19 but I suspect that if that is to be a surrogate avoided
20 cost for PacifiCorp, those projects are probably in
21 excess of $37.00 a megawatt-hour, so my point is that the
22 answer to the problem of the 10 megawatt cap is to
23 negotiate an IRP-based rate with the utility and while
24 that seems to be a successful endeavor for Ridgeline and
25 the Rockland proj ect, you can review the affidavit in the
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56 COLLOQUY
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10
1 Cedar Creek cases as to the compelling reason why that
2 will never be a successful endeavor for PacifiCorp.
3 COMMISSIONER SMITH: Are there questions
4 for Mr. Williams? Mr. Lowe.
5 MR. LOWE: Hello, this is John Lowe. We
6 have no comments other than the ones that have already
7 been submitted.
8 COMMISSIONER SMITH: Thank you, Mr. Lowe.
9 Mr. Ferney.
MR. FERNEY: Thank you, Madam Chairman. I
11 just briefly have two comments here, the first being that
12 in reviewing the comments that have been submitted in
13
14
particular by Idaho Power and Avista, what we're looking
at in regards just to solar is a little bit of a
15 disconnect in the sense that solar is a type of renewable
16 energy that is providing its capacity just when the peak
17 times utilities need. For example, you won't have hardly
18 any flow coming during the evening time, meaning when the
19 sun is down, but you certainly will during midday which
20 correlates strongly in the summertime, for example, to
21 peak air conditioning uses and different things of that
22 nature, so I think that as far as speaking about solar,
23 it's uniquely positioned to be in a different spot than,
24 say, wind, for example.
25 Secondly, I would just make a point that
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1 there hasn i t been any particular decision regarding an
2 effecLi ve date, if any, for the other renewable energy
3 sources, solar being one of them. I think certainly that
4 should that be, which we would argue strongly that it
5 should not apply to solar and other type renewable
6 energy, but should it, certainly some type of a
7 grandfathering-in process would be appropriate based upon
8 factors that the Commission in previous years has looked
9 to, so with that, thank you.
10 COMMISSIONER SMITH: Are there questions?
11 Thank you.12 Mr. Miller.
13 MR. MILLER: Thank you, Madam Chairman,
14 members of the Commission. Let me start by introducing
15 Mr. Paul Martin who is seated to my left, your right, who
16 is our client in this matter, although the technical name
17 for the party is Intermountain Wind, but it's really
18 Mr. Martin. Mr. Martin is not a corporate developer.
19 Mr. Martin is not a large multi-national corporation.
20 Mr. Martin's family is fortunate enough, I guess, to own
21 agricultural land in eastern Idaho that has the potential
22 for being a reasonable wind resource. Mr. Martin for two
23 years has been in the process on his own attempting to
24 develop a single 10 average megawatt project on that
25 property and has gotten the proj ect to the late stage of
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1 development.
2 All of the interconnection studies have
3 been done. All of the interconnection fees have been
4 paid. All of the land use permits have been obtained and
5 Mr. Martin is in the late stage of contract negotiations
6 for a purchase power agreement with PacifiCorp. Mr.
7 Martin as I'll touch on later is Exhibit A for the type
8 of entity or person that PURPA was intended to facilitate
9 and promote, and as I'll further develop in my hopefully
10 brief comments, whatever you do in this case, it should
11 not operate in such a way that harms a project and a
12 family like the Martins.
13 As I've indicated, the proj ect is in
14 eastern Idaho and would be in PacifiCorp' s service
15 territory and that's, I think, relevant for a couple of
16 reasons, one of which Mr. Williams touched upon and that
17 is that PacifiCorp does not use the AURORA model. It
18 uses some entirely different model that has never really
19 been tested or vetted in the State of Idaho.
20 Secondly, counsel for PacifiCorp in his
21 very clear remarks initially made it clear that
22 PacifiCorp i s concern and worry is the problem of
23 aggregated or large wind proj ects coming on to the
24 system. Mr. Martin is not the problem that PacifiCorp
25 worries about and should not be harmfully affected if you
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1 decide that PacifiCorp has a legitimate concern in some
2 other area.
3 Also, thirdly, the reason this is relevant
4 is that unlike the other utilities, PacifiCorp has not
5 made, even attempted to make, a credible claim that it's
6 facing in some sense too much wind. PacifiCorp, to our
7 knowledge, does not at this moment have an operating wind
8 QF in its Idaho service terri tory. Mr. Martin's proj ect
9 is, to our knowledge, the only one that is conceivable to
10 be operational within the foreseeable future, and then to
11 briefly touch on the three topics the Commission
12 identified in its Order, but first, let me make three
13 general observations.
14 The first is that the characterization of
15 the utilities of the PURPA regulatory program and this
16 Commission's implementation of it as you have heard has
17 been uniformly negative, that it's a system fraught with
18 difficulty, it's a burden on everybody in the world, but
19 as Commissioner Kempton's question to Mr. Walker pointed
20 out, there's another way to look at it and that is that
21 it's the legislative policy of this state to promote the
22 creation of renewable energy in the state and it's also
23 true that to the extent that legislative policy has been
24 accomplished, it's been accomplished by your work, by
25 what the Commission has done.
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1 Under our framework of state government,
2 it's really only you that have the tools to carry out
3 that policy, and in recent years the Commission has done
4 a job that I think you should be proud of. You actually
5 have produced a renewable energy industry in Idaho and
6 with that, you have produced the benefits that the
7 legislature sought to obtain of clean energy, jobs, taxes
8 for local taxing districts and so on.
9 As I will also say in a moment, I think
10 it's appropriate for the Commission to make midstream
11 adj ustments to its regulatory policies when necessary or
12 appropriate, but my point here is that as you go into
13 that process of making adjustments, you should do it with
14 an attitude not that PURPA is a bad thing, you should do
15 it with an at ti tude that you have done a good job to date
16 of creating a renewable energy industry in Idaho and if
17 there are adjustments that need to be made to the system,
18 they ought to be made, but it ought to be done with an
19 attitude that this is not a problem or a burden, but it
20 ought to be done with an attitude that these are
21 midstream adj ustments to an otherwise good system that i s
22 accomplishing a good public policy goal.
23 My second general observation is this,
24 that every decision the Commission makes is important.
25 There's no question about that, but it's also true that
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.1 many of the decisions the Commission makes are
2 correctable or self-correcting. If you set a rate in a
3 rate case that it turns out overcollects or undercollects
4 the expected amount, you can always fix that in a
5 subsequent rate case.If you set, for example, a PCA
6 rate~ if it turns out to not be quite right, there's the
7 true-up. There's even the true-up of the true-up, so
.\
8 many of the decisions you make while important are
9 correctable, but every once in awhile you're faced with a
10 decision that if you do it wrong, it can't really be
11 corrected, so if in this case you should order what turns
12 out to be a de facto moratorium and if it as in the past.13 drags on for some unknown period of time and if in
14 consequence you harm Mr. Martin, you harm an industry,
15 you harm the implementation of the legislative policy,
16 you can't really go back and say oops, we got that wrong,
17 we'll fix it.
18 The third general observation I'd like to
19 make that hopefully will guide your thinking is that no
20 regulatory structure is perfect, whether it's in the
21 medical area, whether it's in the financial area, whether
22 it's in the energy area, and regulatory frameworks should
23 evolve to meet changing conditions, so if you now are
24 satisfied that there are changing conditions, it i s.25 appropriate for you to take measures to adj ust the
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1 regulatory structure, but in light of the first general
2 principle I mentioned, the harm that can result if you
3 over-react, it's our urging that any adj ustments you make
4 be tailored as carefully as possible to the identified
5 problem, and the identified problem when we come right
6 down to it in this case is the aggregation question; in
7 other words, whatever remedy you adopt, it should be
8 proportional to the identified problem.
9 It should be a tailored response to a
10 specific thing that may require a correction, and more
11 specifically, what we're suggesting here is that the
12 Commission should develop a framework that will allow
13 small scale PURPA activity to continue, such as Mr.
14 Martin, by maintaining the 10 average megawatt
15 eligibili ty cap for small proj ects while phase two of
16 this proceeding addresses the other issues that have been
17 identified, including the aggregation problems, as ones
18 requiring attention.
19 In a moment I'll discuss a specific
20 proposal to accomplish that goal which I think is a goal
21 you should have, but first, let me make three additional
22 points, and the first is that for small true, what I call
23 true, PURPA proj ects, IRP-based contracting is not a
24 substi tute for published rate contracting. You've heard
25 this from several parties and there are several reasons
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1 why it's true.First, there's no historical evidence
2 that it worked in the last moratorium. To my knowledge,
3 and I think the knowledge of all the parties, the last
4 time we went through a moratorium there was not a single
5 IRP-based contract negotiated and executed, so there's no
6 historical evidence to support the utili ties' claim here.
7 The utility companies have not made any
8 commitment of resources that would be necessary to carry
9 out an IRP-based contracting method.It's so obvious it
10 does not require saying that the IRP methodology wiii
11 certainly be more complicated and require more resources
12 than published rate contracting. The utility companies
13 have not made any commitment to complete the moratorium
14 process wi thin a specific time. It's a wide open,
15 unrestrained process.
16 As we pointed out in our reply comments,
17 the IRP methodology has never produced, and this is even
18 speaking of the AURORA method, let alone the unknown
19 PacifiCorp method, rates that are comparable to published
20 rates for small projects, and on the question of rates,
21 as I've heard the utility presentations, no one has said
22 rates are too high for small proj ects. Only rates are
23 too high for aggregated projects, so the too high rate
24 question does not apply to Mr. Martin and his proj ect,
.25 and finally, the Staff comments also address and identify
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1 four problems with IRP contracting for small proj ects,
2 and in the Staff comments, the Staff indicates the
3 problems are the pricing model is proprietary. It has to
4 be run for each proj ect separately and it's complicated.
5 It will produce different results for different projects,
6 resulting in the possibility of discrimination, and as
7 the Staff says, and I'm quoting here, "Requiring small
8 proj ects to negotiate contracts would defeat the
9 longstanding Commission objective to minimize negotiation
10 costs and complexity for small projects," so whatever the
11 value or merit is of an IRP-based method for large
12 proj ects, it's completely incompatible with small
13 proj ects.
14 The second point I'd like to make is that
15 a proposal to exempt non-wind projects from an
i 6 eligibili ty reduction but leave small wind proj ects
17 subj ect to the eligibility reduction is not a reasonable
18 solution.First, it fails what I call the
19 proportionality principle that I've discussed indirectly
20 before and that is this: Small wind is not the problem.
21 Projects like Mr. Martin's project are not the problem,
22 so if small wind proj ects are swept up in the reduction,
23 then the remedy is broader than the identified problem
24 because it's actually causing harm to things that are not
25 the problem, and secondly , it artificially gives some
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1 generation technologies an advantage over small wind.
2 I think the Commission has always been
3 careful not to discriminate or differentiate among
4 generation types recognizing the competi ti ve disadvantage
5 that would cause one or the other, and my third general
6 point is that the central or a central purpose of PURPA
7 is to protect market access for small proj ects and the
8 Commission has ample legal authority to implement a
9 program that achieves that purpose. This legal point is
10 so well-established that I'll not even spend time
11 discussing it, but rather point you to the j oint reply
12 comments of the Idaho Conservation League and the
13 Renewable Northwest Proj ect which discussed that in some
14 detail.
15 Now, let me turn to what Renewable Energy
16 Proj ect, Idaho Conservation League and Intermountain have
17 proposed as a solution and Commissioner Smith alluded to
18 ita few moments ago. It is contained in the reply
19 comments of ICR and Renewable Energy Proj ect, so it's
20 been in circulation qnd in front of the parties for some
21 time. We're not, though, recognizing the scope of the
22 issues you've scheduled for today, asking that you take
23 definitive action with respect to this proposal today,
24 but that it be considered as if the Commission, hopefully
25 the Commission, will conclude that it provides a
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1 reasonable basis for further discussion of how to adopt a
2 tailored remedy, and I'll just make a couple of comments
3 regarding the proposal.
4 Staff has raised the practical and
5 potential legal problems with a distance-based rule, so
6 the proposal we have put forth does not incorporate
7 distance as a factor, and as with any policy or rule, the
8 parties have raised the gaming concern, that somebody
9 will find a way around whatever system you put in place,
10 but I think it's always true that parties will look for
11 means to operate wi thin a framework that's in their
12 economic self-interest and in my mind, there's nothing
13 really surprising about that. It's not illegal. It's
14 not immoral, but there are times when government can
15 legitimately redirect that self-interest if it's being
16 pursued in a way that's harmful to the public interest
17 and I think this proposal goes a long way in addressing
18 that because it's in effect self-policing.
19 It requires contractual warranties; that
20 is, the party has to warrant that it's not in violation
21 of the rule and the warranty is linked to a default so
22 that if the contract or the seller is found to be in
23 violation, it's an event of a default and from a
24 practical standpoint, people who finance these projects
25 will be very careful to police both the execution and the
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1 performance of contracts to be sure there is not a
2 defaul t, so let me just conclude this way:I have a
3 friend who thinks that every circumstance in life can be
4 explained by a movie analogy and the analogy that comes
5 to my mind in this case is the famous Marx Brothers movie
6 "Duck Soup" and you'll recall in that movie, Groucho is
7 the king of Freedonia and he's married to this dowager
8 queen, but he has an eye for all the princesses in the
9 castle, and one time the queen finds Groucho apparently
10 hugging one of the princesses and she says, "What are you
11 doing?" And he says, "Nothing improper," and then a long
12 speech why it's not improper and he concludes by saying,
13 "Who are you going to believe, me or your eyes?"
14 Well, in this case I think the question
15 kind of is who are you going to believe, the utilities or
16 the things that you can see with your eyes, and the
17 things that you can see with your eyes are that the
18 proposed de facto moratorium would be harmful to many
19 people. The things that you can see with your eyes are
20 that the identified problem can be addressed in a way
21 that it does not cause harm to other people and so based
22 on what you can see with your eyes, we ask you to follow
23 those eyes and come to a conclusion along the lines we
24 have suggested. That i s all I have to say.
25 COMMISSIONER SMITH: Do we have questions?
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1 We have been going for quite a while now. I think we
2 should take a break and come back at 11: 40.
3 (Recess. )
4 COMMISSIONER SMITH: We'll go back on the
5 record.I think we're to Ms. Davis.
6 MS. DAVIS: Thank you, Commissioner, I'm
7 Shelley Davis and I had initially anticipated just
8 si tting in the back of the room and being quiet today,
9 but having listened to what I've heard so far and being
10 in the line of the work I am, I'm compelled to make a few
11 brief comments.I represent intervenors Twin Falls Canal
12 Company and North Side Canal Company and they are
13 nonprofi t irrigation companies in southern Idaho and over
14 the past 20 years have implemented and developed some
15 small conduit, small scale hydropower proj ects within
16 their irrigation canal systems. Most of these proj ects
17 range between two and eight megawatts and so would
18 obviously be outside of the eligibility cap in the event
19 that this Commission were to lower that rate eligibility
20 cap for all qualifying facilities.
21 They are irrigation conduits where these
22 facili ties are placed and so they do produce during the
23 peak season, the summer season, during the peak load
24 hours that Idaho Power is producing power in this region.
25 They've been an outstandingly reliable source of power
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1 because of their location in the Snake River system above
2 Milner. The water during the summer season is reliable
3 and does provide an excellent source of power to Idaho
4 Power Company. We've worked together well for many years
5 to get these facilities on line and running and to that
6 end, we would encourage the Commission not to lower the
7 rate eligibility cap to a point that would make it
8 infeasible for them to continue to develop additional
9 small scale hydropower in their conduits.
10 At this time the North Side Canal Company
11 has 19 additional Department of Water Resources permits
12 allowing them to build up to 19 additional facilities
13 wi thin the next five to ten years. They're actively
14 working with developers to bring some of these systems on
15 line.I don't anticipate that all 19 will be developed,
16 but some subset of those we hope to have on line wi thin
17 the next decade.
18 As I raised in my initial comments to the
19 Commission, the federal government has raised its
20 interest in small conduit hydropower to an unprecedented
21 level in the last year. There was a 2010 Hydropower
22 Improvement Act introduced last Congressional session by
23 Senator Murkowski' s office. Senator Crapo was a
24 co-sponsor of that bill and I have it on good information
25 that they are attempting to repackage that bill and hope
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1 to reintroduce it by the end of February, beginning of
2 March. That bill is aimed at reducing barriers,
3 regulatory barriers specifically, to getting small scale
4 hydropower in development in the United States, including
5 condui t hydropower.
6 The FERC, Federal Energy Regulatory
7 Commission, has entered into memorandums of understanding
8 wi thin the last six months with the states of Colorado,
9 Oregon and Washington wherein the FERC will work
10 specifically with those states to identify additional
11 small scale conduit hydropower facilities and help them
12 wi thin their states and wi thin the federal government
13 reduce regulatory barriers to getting those into
14 production as well.
15 I think if anyone here listened to the
16 President's address on Tuesday night, he raised as well
17 that it's his goal for the nation by 2035 to have an 80
18 percent increase in renewable energy wi thin the United
19 States, and so while Idaho is not always adverse to
20 bucking the national trend, I think in this particular
21 instance that if the Commission were to take the action
22 that the utili ties are proposing that it would serve a
23 real disservice to renewable energy producers in the
24 State of Idaho and could infringe on them being able to
25 take advantage of some of the benefits that we see
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17
1 potentially coming out of Washington D. C. in the not too
2 distant future.
3 I would stand for any -- oh, I wanted to
4 raise one additional thing. The canal companies have
5 reviewed the proposal that was presented by the
6 Conservation League and Renewable Northwest Project and
7 are in support of that potential solution, specifically
8 they like the fact that there isn't a mileage requirement
9 or a mileage issue with the siting of the hydropower
10 projects. Because of the way the canal system is set up,
11 if there were a one-mile or five-mile distribution, we
12 might be in a position where otherwise viable proj ects
13 would be prevented from being developed and we think that
14 the Conservation League's proposal would be a good
15 solution that would eliminate that mileage barrier as
16 well, so I'll stand for questions.
18 questions? Thank you, Ms. Davis.
COMMISSIONER SMITH: Are there any
19
20
Mr. Jepson.
MR. JEPSON: Yes, I'm here. May I make a
21 preliminary comment? Although your Rules of Procedure
22 that I reviewed allow for the appearance of an
23 out-of-state attorney before the Commission and although
24 I am an out-of-state attorney, Ilm licensed in Utah, I am
25 not appearing here today as an attorney representing a
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.1 client, but rather in the capacity as one of the two
2 owners of Blue Ribbon Energy and I just wanted to make
3 that clear in case there was any question about that.
4 COMMISSIONER SMITH: Well, the Commission
5 appreciates that having been sued by the Idaho State Bar
6 for allowing unauthorized practice of law, so as an
7 owner, we appreciate your participation and please go
8 ahead.
9 MR. JEPSON: Thank you.I think if I
10 appeared in either capacity it would not be illegal and
11 it would not get you in trouble, so I wouldn't cause the
12 Commission any problems. Anyway, I have several comments.13
14
that I would like to make. First, I would like to adopt
as part of Blue Ribbon's arguments everything that Pete
15 Richardson argued. I would also li ke to adopt in behalf
16 of Blue Ribbon almost everything that Mr. Miller argued,
17 except for his confinement that or argument seemingly
18 defining a small power as a 20 megawatt facility, 10
19 average megawatts that his client is trying to develop.
20 With that exception, let me just proceed down four or
21 five points.
22 First of all, let me say that Blue Ribbon
23 Energy is among everyone who is appearing before the
24 Commission today kind of the new kids on the block, so we.25 don't have, neither of us has, the experience, the
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1 knowledge or sophistication of probably any of the other
2 people who have spoken so far, so my main concern is that
3 I hope I don i t embarrass myself today and if I do say
4 something that's wrong or out of order in some way, I
5 hope that everyone present will be somewhat forgiving.
6 I also would like to make a motion. I
7 assume that under the Rules of Civil Procedure it's
8 appropriate or allowed to make an oral motion during a
9 hearing. Assuming that to be the case, I would make a
10 motion on behalf of Blue Ribbon to dismiss the joint
11 peti tion filed by the utili ties for several reasons.
12 One, I don't believe that it's brought or asserted in
13 good faith. No.2, I don't believe that the utili ties in
14 their petition or today in their arguments have presented
15 a basis upon which the Commission can grant relief, and
16 that 3, I believe that this j oint petition constitutes or
17 it could be argued that it constitutes an effort to
18 terminate its obligations to sign PURPA contracts with
what they are calling aggregated proj ects .
Although they expressly,I think,deny
that,it seems apparent that that is in fact what is
happening and I suggest that that is in violation of
19
20
21
22
23 federal law, specifically Title 18 Code of Federal
24 Regulation section 292, subparagraph 309, et seq. and so
25 that's my motion. Now, as to several other points --
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1 COMMISSIONER SMITH: Mr. Jepson?
2 MR. JEPSON: Yes.
3 COMMISSIONER SMITH: Do you wish the
4 Commission to take up your motion at this time and gain
5 replies from the petitioners or do you want to conclude
6 your comments and have us take that up after you're
7 finished?
8 MR. JEPSON: I would prefer after I'm
9 finished and
10 COMMISSIONER SMITH: All right, we will do
11 that.
12 MR. JEPSON: Thank you. Others have
13 requested some rebuttal time, I'm assuming that you will
14 also allow some surrebuttal which I'd like to reserve the
15 right for.
16 COMMISSIONER SMITH: You should not make
17 too many assumptions like that.
18 MR. JEPSON: Well, again, I'm the new kid
19 on the block, so maybe -- well, they get rebuttal time
20 and I'm just used to in trial you always have
21 surrebuttal, so I would like you to at least consider
22 that.
23 COMMISSIONER SMITH: Mr. Jepson, this is
24 not a trial. It's an administrative process and my view
25 is that the person making the applicatlon or the
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.1 applicant in the case always gets the last word, so
2 anything you need to say you should say right now.
3 MR. JEPSON: I appreciate that educational
4 comment for my benefit. First, then, I'd like to
5 continue our first argument would be that this procedure,
6 that is, the joint petition filed by the utilities, I
7 believe is in violation of Title 18 CFR 292.309, et seq.
8 in that the federal statute there which is part of the
9 PURPA Act has a specific provision entitled "Termination
10 of Obligation to Purchase Power" and it requires an
11 application to FERC in order to relieve them of this
12 obligation..13
14
I think that the joint petition
consti tutes a subversion of that clear statutory
15 procedure in that they are trying now to go through the
16 state Public Utilities Commission, avoid a filing with
17 FERC to accomplish the same end which is to lower the cap
18 and thereby essentially create a moratorium ending or
19 terminating their obligation to enter into new PURPA
20 contracts.I think it's an illegal procedure.I think
21 it violates that statute and this Commission ought to
22 dismiss their petition for that reason, among other
23 reasons I'm going to get to here in just a minute.
24 Our next argument would be that the cap.25 that is being requested by the joint petition flies in
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1 the face of other federal law. For example, this whole
2 argument about aggregation seems to undermine a
3 section -- well, Title 18 CFR 292 and the following
4 subsections which specifically allows for the aggregation
5 of up to 80 megawatts at one site requiring
6 sub-facilities of, say, 20 megawatt nameplate to be
7 located in one site and they're required to be within one
8 mile and so far as I have been able to determine and,
9 again, I admit I'm the new kid on the block here, but it
10 appears to me that this whole argument of aggregation
11 being somehow illegal or disfavored or that it ought to
12 be outlawed somehow by the IPUC runs contrary to this
13 specific authorization of section 210 (m) which is the new
14 section of PURPA, and I gave you the citation here, which
15 allows for a PURPA development up to 80 megawatts, and we
16 would encourage the State of Idaho through the IPUC to
17 not only adopt in full measure, but enforce that
18 provision of the federal law which allows development of
19 a PURPA facility up to 80 megawatts in one site and still
20 be eligible, according to the federal regulations they
21 would still be eligible, for the published avoided cost
22 rate.
23 COMMISSIONER SMITH: Mr. Jepson?
24 MR. JEPSON: Yes.
25 COMMISSIONER SMITH: I'm very sorry to
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1 interrupt, but your comments are being detracted by a
2 squeaking sound which I believe could be your chair.
3 MR. JEPSON: It's probably my chair.
4 COMMISSIONER SMITH: So if you have any
5 WD-4a, you might want to use it, but it is distracting
6 from the points you're trying to make.
7 MR. JEPSON: Thank you. I'll get out of
8 that chair. All right, were you able to hear what I
9 said?
10 COMMISSIONER SMITH: Yes, we were and
11 you're much clearer now.
12 MR. JEPSON: I apologize to everyone.
13 There was another argument made, I believe, by Mr. Miller
14 wi th which I would like to take exception. He talked
15 about contracts after they're signed shouldn't be
16 disrupted by anything the IPUC does with regard to this
17 j oint petition; however, there are others like Blue
18 Ribbon who have a development, a proj ect, underway here
19 in eastern Idaho in the PacifiCorp area, so Mr. Miller's
20 client is not the only one that could feasibly come on
21 line here in the near future, and we have a draft PPA
22 which we've obtained from PacifiCorp and Mr. Kaufmann
23 which has not been reduced to any final form yet, but
24 we're in the process and we would ask and respectfully
25 request that nothing the IPUC does with regard to this
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.1 joint petition interrupt or disallow us from finishing
2 our proj ect, because like I'm sure every other private
3 developer, we i ve invested a great deal of time and money
4 and effort to get to this point and to be cut off by this
5 joint petition would seem fundamentally unfair and
6 financially harmful.
7 Let's see. The other point I wanted to
8 argue is this argument about the people or that there
9 should be some rule providing for disaggregation of
10 proj ects that would not allow a proj ect that's greater
11 than, say, 20 megawatt nameplate to be developed together
12 wi th other 20 megawatt proj ects and then separate PPA' s.13
14
signed, as I understand the arguments being made by the
utili ties is that that makes the proj ect complex. They
15 think it's gaming. It i S taking advantage, and I think
16 Mr. Richardson correctly identified the fact that if that
17 is going on, it is simply a matter of taking advantage of
18 the rules and regulations which are in place.
19 It's also a result I suggest of not
20 specifically adopting and enforcing in Idaho the 80
21 megawatt rule that's contained in Title 18 CFR 292 which
22 allows for a PURPA proj ect which would be an eligible QF
23 proj ect for the published avoided cost rate. Since that
24 rule isn't particularly enforced so far as I have been.25 able to discover and it doesn't sound like it and I think
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1 the evidence of that is the j oint petition, and if that
2 rule were followed in Idaho, which I think it should be
3 because it's federal law, then we wouldn't have the
4 arguments from the utili ties that these smaller
5 developers are gaming or playing games with the system.
6 In fact, I think that what the private
7 developers are doing, including Blue Ribbon Energy, is
8 essentially trying to follow that 80 megawatt rule when
9 the utili ties won't recognize it and so I think the IPUC
10 has an obligation, a legal obligation, to recognize that
11 statute and its subsections and to enforce that and allow
12 pri vate developers to develop 80 megawatt sites and then
13 this aggregation/disaggregation issue would entirely
14 disappear as it should disappear, only it disappears by
15 way of compliance with federal law, not by way of a joint
16 petition to in effect undermine the federal law.
17 I think those are my comments. Thank
18 you.
19 COMMISSIONER SMITH: Okay, let's see if we
20 have any questions. Okay, I guess we will now go to
21 consideration of Mr. Jepson's motion and ask for
22 responses from the applicants. Mr. Andrea?
23 MR. ANDREA: Andrea, yes, thank you,
24 Madam Chair.I appreciate the opportunity to respond to
25 that motion.I'm not quite sure where to start. The
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1 motion seems to be high on hyperbole and short on correct
2 legal analysis, unfortunately, so I' II hit a couple of
3 points, but I'm sure that my colleagues will probably
4 want to discuss a couple others.
5 I think one thing just as a matter of, I
6 guess, decorum for lack of a better word, the hairs on
7 the back of my neck always stand up when I hear
8 accusations of bad faith and I take fairly strong
9 exception to those. I think they're unwarranted and
10 should be reserved only for those times when it really is
11 truly warranted, so II d just note that.
12 Wi th regard to the gentleman's motion from
13 Blue Ribbon, Avista is certainly not asking to terminate
14 any obligations to sign any contracts with any PURPA
15 developer. We take our obligations with regard to PURPA
16 very seriously and we will fulfill those obligations in
17 good faith.
18 Wi th regard to the law and the 80
19 megawatts the gentleman sited repeatedly, it almost bears
20 no need to rebut, but just for the sake of the record,
21 that 80 megawatts is the qualification requirement for
22 PURPA proj ects and the utili ties take no issue with that.
23 The issue is with regard to the eligibility cap for
24 published avoided cost rates and I would direct the
25 gentleman from Blue Ribbon to 18 CFR 292.304 (c) (1). That
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1 particular rule allows for the published avoided cost
2 rate eligibility cap to be 100 kW. State commissions
3 have the authority to set it at a different level, but
4 the federal law allows it to be set as low as 100 kW, and
5 I think most people in this room understand that, so I
6 apologize for taking the time to have to restate that.
7 We are not talking about not fulfilling a
8 PURPA obligation. We're talking about what the right
9 rate is for the published avoided cost or what rate is
10 the right rate for a particular proj ect. If a proj ect is
11 larger, it should get an avoided cost rate calculated to
12 an IRP methodology that provides the correct avoided cost
13 rate that is more accurately reflective of the utility's
14 actual avoided cost rate. For small proj ects that are
15 truly small, we're fine with the published avoided cost
16 rate. For those 100 kW and less, it makes perfect sense,
17 so I'll turn it over to my colleagues to further rebut
18 the motion. Thank you.
19 COMMISSIONER SMITH: Mr. Walker, did you
20 want to add anything?
21 MR. WALKER: Just that I ask that the
22 motion be denied based on comments from counsel for
23 Avista.
24 COMMISSIONER SMITH: Mr. Kaufmann.
25 MR. KAUFMANN: Thank you, Madam Chairman.
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1 PacifiCorp feels the motion should be denied. As to Mr.
2 Jepson's accusation that PacifiCorp acted in bad faith, I
3 strenuously deny that. PacifiCorp, it may be noted, does
4 not pay QF contract costs. These costs are borne
5 ul timately by the ratepayers. PacifiCorp is acting to
6 protect the interests of ratepayers and I might add that
7 the Commission Staff also is in support of the three
8 utili ties i petition, so presumably, he's saying that the
9 Commission Staff also acted in bad faith. I think that
10 Mr. Jepson may see bad acts too easily in his own mind,
11 but those are opinions and not the legal definition of
12 bad faith.
13 As for the bases being lacking in the
14 motion, his motion is saying that the utilities' petition
15 lacks any basis, the proliferation of disaggregated
16 projects is self-evident. The Commission may note that
17 from the signed contracts with wind projects that have
18 been filed with it in 2010, and as I noted in the reply
19 brief, an evidentiary hearing is not required for the
20 Commission to modify its prior orders. regarding the 10
21 average megawatt cap and this principle has also been
22 held by the public utilities commissions of California
23 and Oregon. That's in my reply brief; therefore,
24 PacifiCorp/Rocky Mountain opposes the motion. Thank you,
25 Madam Chairman.
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1 COMMISSIONER SMITH: Mr. Jepson, do you
2 have any further comments to make on your motion?
3 MR. JEPSON: I'd like to make two
4 comments. I didn't catch the first responder's name,
5 but--
6 COMMISSIONER SMITH: It was Mr. Andrea for
7 Avista.
8 MR. JEPSON: -- Mr. Andrea cited
9 292.304 (c) (1), I think it's interesting to note that
10 292.304(c) (2) has important wording. Although (c) (1)
11 says, "There shall be put into effect standard rates for
12 purchases from qualifying facilities with a design
13 capacity of 100 kilowatts or less," (c) (2) says, "There
14 may be put into effect standard rates for purchases from
15 qualifying facilities with a design capacity of more than
16 100 kilowatts," so (c) (1) is not wording that precludes
1 7 what I've argued, and neither did the arguments say
18 anything about -- I mean, he admits that 80 megawatts is
19 the standard, but if you're dealing -- and I understand,
20 you know, everybody looks at things differently.
21 When I was a prosecutor, I looked at a
22 case one way. When I did defense work, I looked at the
23 same kind of case from a totally different viewpoint and
24 the same is true here. If you're a utility, you look at
25 development from one perspective. I f you're a private
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1 developer trying to develop a proj ect, you're looking at
2 it from a whole different perspective, and it seems to me
3 that especially private developers, small developers
4 should be recognized as small developers up to 80
5 megawatts for a particular facility at one site.
6 No one here has talked in terms of a small
7 developer being, you know, defined as up to 80 megawatts.
8 Mr. Miller tal ked about a small developer, small power
9 producer being 20 megawatts, but a small power producer
10 by federal law is up to 80 megawatts, but the utilities
11 from my experience so far, which is limited and I admit
12 that, they will not agree to pay you the published
13 avoided cost rate if you're up to 80 megawatts and that's
14 forcing the developers to disaggregate and do 20 megawatt
15 PPA' s when they could do one PPA for 80 megawatts if they
16 got the avoided cost rate which I claim and I argue, I
17 may be wrong in this, but so far it appears to me that it
18 would be appropriate to argue that if you develop an 80
19 megawatt site and you're a QF, you ought to be eligible
20 for the published avoided cost rate and I think that's
21 the direction the I PUC ought to go here, and with regard
22 to the allegations that I'm saying they did this in bad
23 faith, I never said they did it in bad faith.
24 I said it wasn't asserted in good faith
25 and that's based upon the clear argument that I made. It
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1 was not intended as personal or derogatory in any sense,
2 but if they are trying to avoid or trying to accomplish
3 in effect a termination of their obligation, even though
4 they deny it, the effect is the same in what they're
5 trying to do. They're trying to effect a termination of
6 their PURPA obligations which is supposed to be through
7 an application to FERC, not to the IPUC, and I see what
8 they're doing here as an attempt to circumvent the
9 federal procedure that's in place by statute by going to
10 the state PUC Commission instead under the guise of
11 setting a cap instead of just coming right out filing
12 their motion or their petition with FERC and saying we
13 ought to be relieved from our obligations here, and that
14 in effect is what they are doing, even though they say,
15 well, we intend to fulfill our PURPA obligations. We
16 take that very seriously and so forth.
17 It's obvious that they are taking it
18 seriously if they're trying to circumvent it and in
19 effect achieve a termination without going through the
20 proper federal procedures and so I think my comment about
21 not brought or asserted in good faith is accurate based
22 upon that set of facts and on the federal statutes. No
23 personal jab was intended against anyone and if they took
24 it personally, I apologi ze for that.
25 COMMISSIONER SMITH: Mr. Jepson, I'm going
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.1 to deny your motion to dismiss. While the Commission may
2 set rates for proj ects larger than 100 kilowatt-hours,
3 it's our obligation shall set rates for that size or
4 smaller, so we appreciate your participation here, but
5 your motion is denied and we'll now to move to the
6 comments of the Staff. Ms. Sasser.
7 MS. SASSER: Thank you, Chairman Smith,
8 Commissioners.I'm going to try and bring us back out of
9 the weeds a little bit, although it's been tromped down
10 pretty well, so I might find my way back in. Since PURPA
11 was first implemented in Idaho in the early 1980s, this
12 Commission in setting avoided cost rates has elected to.13 draw a clear distinction between large and small QF
14 proj ects . Avoided cost rates for small QFs have been set
15 in a generic manner based on assumed cost of a surrogate
16 avoided resource.
17 In January 1995, this Commission adopted a
18 different methodology for large QFs. In Order No. 25884,
19 the Commission adopted what is now commonly referred to
20 as the IRP methodology. The IRP methodology
21 incrementally updates the utility's avoided cost to
22 recognize the impact of adding new and large generation
23 resources. The Commission approved the IRP methodology
24 for large QF projects because the method better captures.25 the changing company avoided cost as large proj ects are
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.1 added to the system and because it recogni zed -- because
2 the IRP methodology recognizes the specific
3 characteristics of various types of generation resources.
4 For small resource additions, the change
5 in a utility's avoided cost is small. As new resource
6 addi tions grow beyond the utility's needs, the cost that
7 the utility avoids by acquiring the new resource declines
8 significantly.In fact, if the utility does not need any
9 addi tional resources, FERC has recognized that it's
10 possible for a utility's avoided cost to calculate as
11 zero.
12 When large QFs are added to a utility's.13 renewable portfolio, but the QFs disaggregate in order to
14 qualify for the published rate, the avoided cost paid to
15 the QF becomes inaccurate, because under the published
16 rate methodology, there's no mechanism to reflect the
17 utili ty' s reduced avoided cost. The failure to reflect
18 this decline in avoided cost with the addition of large
19 new resources violates PURPA because utili ties ultimately
20 pay these disaggregated QFs more than the true avoided
21 cost to the utility.
22 The Commission recognized and discussed
23 this very issue when it adopted the use of the IRP
24 methodology in 1995. Consequently, the published rates.25 are not a true approximation of the utility's avoided
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1 cost for the next small incremental unit of generation
2 because the effect of aggregating several small proj ects
3 does not amount to an incremental unit of generation. It
4 amounts to the type of very large resource that a utility
5 acquires through its RFP process.
6 Indeed, as the utili ties represented in
7 their arguments today, many of the disaggregated wind
8 proj ects were originally presented to the utili ties
9 through the RFP process. When the proj ect was not chosen
10 through an RFP, the developer disaggregated the larger
11 proj ect and presented it in 10 average megawatt pieces to
12 avoid calculation under the IRP methodology and making
13 each 10 average megawatt piece eligible for the published
14 avoided cost rate.
15 Currently disaggregated wind proj ects are
16 contracting for a rate that exceeds the utility's avoided
17 cost and violates the intent of PURPA and the guidelines
18 established by FERC. The logic for reducing the
19 eligibility cap in 1995 holds true today. By lowering
20 the threshold, we strike a reasonable balance between
21 encouraging the development of independent al ternati ve
22 energy technologies with the need to protect ratepayers
23 from paying for larger resources which have not proven
24 their cost effectiveness.
25 Wind has unique characteristics that allow
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1 proj ects to be developed at a larger scale and to be
2 disaggregated into 10 average megawatt pieces in order to
3 qualify for a published avoided cost. It i S precisely
4 this disaggregation that causes the published avoided
5 cost to become an inaccurate reflection of the utility's
6 true avoided cost. Reducing the published avoided cost
7 eligibili ty cap for wind to 100 kilowatts will prevent
8 large wind proj ects from obtaining an inaccurate
9 published avoided cost while still allowing those wind
10 projects and wind QFs to avail themselves of the IRP
11 methodology that better recognizes the specific
12 characteristics for those types of resources.
13 Staff continues to believe that because
14 wind proj ects have been by far collectively the largest
15 and most plentiful projects in recent years, they
16 represent the greatest immediate concern for utili ties
17 and their ratepayers. FERC has granted the commissions
18 wide latitude in implementing the federal law and
19 regulations. Consequently, Staff recommends that the
20 reduced cap can and should be applied only to wind. That
21 said, Staff remains open and willing to discuss the
22 possibili ty of adopting a theory with legally defensible
23 parameters that distinguishes large and small QFs and
24 allows the QFs to continue to receive a 10 average
25 megawatt eligibility cap.
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1 COMMISSIONER SMITH: Thank you, Ms.
2 Sasser. That appears to be on my list every
3 representati ve of parties appearing today.Is there
4 anyone I've missed? Okay, now, we will return to our
5 applicants for their very brief summation.
6 MR. WALKER: Thank you, Madam Chairman. I
7 just have a few points and I'll be as brief as possible.
8 First of all, I wanted to get back to Commissioner
9 Kempton's question that I was unable to answer at first
10 regarding the 48 million calculation. I'm on page 8 of
11 Idaho Power's comments. We see that that was estimated,
12 the costs were performed through 2020, market costs
13 through 2020, and page 18 also has some further
14 explanation of that calculation and numbers.
15 Secondly, there's been some talk by the
16 Commission and many of the parties of ICL and Renewable
17 Northwest's proposal. There's also been talk of a
18 five-mile separation as possible solutions to a
19 disaggrega tion issue. I wanted to reiterate Idaho
20 Power's position that we have taken those similar
21 positions in the past and in fact, brought those to the
22 Commission. However, at this point in time are convinced
23 and believe that a much better solution to the
24 disaggregation problem is what would result from a
25 lowering of the cap to 100 kilowatts which would
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1 eliminate the disaggregation problem from our
2 perspecti ve.
3 Next, I would like to address -- we heard
4 some talk of how the utili ties are so negative about
5 PURPA and all things PURPA and all this and tied in that
6 is this assumption and this allegation that the IRP-based
7 avoided cost rate methodology somehow always results in a
8 price that's less than the avoided cost and that just
9 simply is not true. Being a methodology that takes into
10 account a specific project and its characteristics and
11 its generation profile, it does not always reflect a
12 resul tant price that's lower than the published rate
13 price.
14 In our reply comments, we gave an example
15 of a representative solar proj ect, 20 megawatt solar
16 project, with a typical southern Idaho generation profile
17 run through AURORA, IRP-based methodology, that results
18 in a 20-year levelized price of $97.00 which far exceeds
19 the published rate for the same time period. What we see
20 here is a reflection of just what Idaho Power believes is
21 the benefit of this methodology in that it takes into
22 account the true value and the need of that energy for
23 the utility and its system.
24 Proj ects that deliver energy when the
25 utili ty needs it in conj unction with not delivering the
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1 energy when the utility does not need it and is already
2 long results in very favorable pricing reflective of that
3 need and value on the utilityl s system through the
4 IRP-based methodology. Such proj ects such as solar,
5 possibly hydro, other QF projects that are either able to
6 shape their energy or have a natural generation profile
7 that matches the utility i s needs fare quite well.
8 Unfortunately, resources such as wind or
9 other 24/7 flat-out projects that provide energy at all
10 hours with no regard for when the utility needs it or
11 when it's useful on the system, they take a hit in that
12 analysis because of all the excess energy that the
13 Company then has to deal with and move around and take at
14 a loss and the resultant increased cost to customers that
15 resul ts from that.
16 Next point, Mr. Richardson alludes to some
17 type of bad faith signing of contracts on behalf of Idaho
18 Power which is definitely not the case and very offensive
19 that I believe needs to be clarified. Idaho Power was
20 very clear in its filings with all of those contracts
21 since November 5th that it was filing these contracts for
22 the Commission's review as is required, as is a necessary
23 part and component of its obligations as a regulated
24 utili ty in the State of Idaho, a necessary component for
25 this Commission to exercise its independent evaluation
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.1 and make a public interest determination on those
2 contracts, on the rates, on the effect to the public and
3 the customers, and Idaho Power also in recognizing that
4 it has a legal obligation under PURPA, under federal law,
5 under this Commission's orders to proceed in good faith
6 and execute contracts under the current rules for
7 published rates for 10 average megawatts had no choice
8 and met its legal obligations, negotiated and signed
9 contracts and submitted them to the Commission for its
10 review.
11 That is quite a different thing than
12 pointing out this Commission's authority to take an.13
14
independent review of those and make its own independent
determination to see if those contracts are in the public
15 interest or not. Nowhere in those applications or
16 anywhere has Idaho Power stated that it seeks approval or
.
17 It signed therej ection of any of those contracts.
18 contracts, it submitted them to the Commission and asked
19 for the Commission's review of those contracts as is its
20 obligation, the Company i s obligation as well as the
21 Commission's.
22 My next couple will be a little bit
23 shorter, I promise. One quick note about the wind
24 integration and some of the allegations that were poised
25 wi th the Company with that. You know, Idaho Power has
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.1 updated its -- it considers the IRP process to be a
2 mechanism in which to update its wind integration. It
3 did analysis and updated that information as part of the
4 2009 IRP.It's currently conducting analysis and doing
5 an update of wind integration as part of its 2011 IRP.
6 Allegations that that is not something that's being
7 moni tored or looked at are wrong.
8 Also, Mr. Richardson i s allegation that the
9 IRP-based methodology that utilizes AURORA in its
10 methodology does not include capital costs in that
11 calculation is incorrect, also. Capital costs are added,
12 are an added piece of that methodology in addition to the.13 interview pricing that comes out of the AURORA model.
14 One thing that Mr. Miller addressed was
15 this whole idea of promoting renewables and our state
16 legislature i s promotion, the federal law's promotion,
.
17 this Commission's promotion of renewable energy and just
18 a couple of quick reminders. The promotion or the
19 incentive that's embodied by the federal law that's
20 administered by this Commission is the requirement to
21 contract and purchase energy from qualified facilities.
22 It is not in the pricing that is established by this
23 Commission for the purchase of that energy.In fact, the
24 federal law tells us how that's supposed to be priced.
25 It's supposed to be priced at the utility's avoided cost.
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.1 Any pricing that is set other than the
2 avoided cost at some incentivized pricing is clearly
3 illegal under PURPA and is not the purpose, stated to be
4 not the purpose, or any purpose in PURPA, and I emphasi ze
5 again, it is the requirement to contract and purchase
6 energy which nobody here today is asking be abrogated or
7 in any way taken away from the utili ties in this case,
8 and one last point, I much enj oyed Mr. Miller i s reference
9 to the movies and references to harm. He talked about
10 harm to developers and harm to his client and harm to the
11 legislature and its pronouncements and warned this
12 Commission to keep its eyes open to that harm, and Idaho.13 Power is here to please ask the Commission to keep its
14 eyes open and look out for the harm to our customers, to
15 the ratepayers, the customers of this state, the public
16 and the public interest that are required to foot the
17 bill that goes to those other people Mr. Miller
18 mentioned, the money that flows from their pockets into
19 their pockets which this Commission is charged with
20 specifically looking out for the public interest and the
21 economics of those folks as well.
22 COMMISSIONER SMITH: Thank you, Mr.
23 Walker.
24 Mr. Andrea, did you have anything to add?.25 MR. ANDREA: Yes, Madam Chair, thank you.
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1 Mike Andrea for Avista. I am going to keep it short.
2 There's an awful lot that has been discussed today and a
. 3 lot to digest. I'm going to talk about three points and
4 only three points. One of the points is Mr. Richardson
5 talked about the capabilities of the AURORA model
6 yielding an estimate of variable running costs as opposed
7 to not an actual avoided cost. In fact, Avista' s IRP
8 methodology does create an avoided cost and I have Mr.
9 Kalich with me today who is our modeling expert. I will
10 leave it to the Commission whether they want Mr. Kalich
11 to speak to this. He could speak to it and provide quite
12 a bit of assistance to the Commission, I believe, and I
13 think it would be worth your time, but at the same time,
14 I recognize that we i ve already used a great deal of your
15 time, but I did want to rebut that issue and if the
16 Commission would like, I'll let Mr. Kalich just speak
17 briefly to that point.
18 COMMISSIONER SMITH: Okay, the
19 Commissioners would allow Mr. Kalich to briefly
20 MR. RICHARDSON: Madam Chairman.
21 COMMI SS lONER SMITH: Mr. Richardson.
22 MR. RICHARDSON: We're prepared to call
23 Dr. Reading --
24 COMMISSIONER SMITH: And we'll be happy to
25 listen to Dr. Reading.
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.1 MR. RICHARDSON: And is Mr. Kalich going
2 to be under oath and subj ect to cross-examination?
3 COMMISSIONER SMITH: Mr. Andrea.
4 MR. ANDREA: Yes, Madam Chair, I could
5 channel for Mr. Kalich, but you're going to get a better,
6 more complete, more accurate response from Mr. Kalich.
7 I i m not offering it as evidence under oath, just as mere
8 context it might be helpful to the Commission. If it
9 would be easier for the Commission, I'd be happy to
10 wi thdraw the request and stand on the comments we've made
11 on that point.
12 COMMISSIONER SMITH: We'll be at ease for.13 a few moments.
14 (Pause in proceedings.)
15 COMMISSIONER SMITH: In the interests of
16 administrative efficiency for the Commission, I think I
17 will reverse myself and say we won't hear from Mr. Kalich
18 today as we recognize this is not the end, but the mere
19 beginning, of all the issues that have been raised, so
20 wi th regard to what the AURORA model does or doesn't do
21 in calculating an avoided cost rate, I'm sure there will
22 be plenty of opportunity to get testimony and have
23 wi tnesses and do cross-exam.
24 Mr. Richardson..25 MR. RICHARDSON: Thank you, Madam
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1 Chairman. I think
2 MR. ANDREA: I'm sorry to interrupt, I had
3 two more --
4 COMMISSIONER SMITH: I know you do, but
5 we're going to settle this issue first. Mr. Richardson.
6 MR. RICHARDSON: Thank you,
7 Madam Chairman. I think this illustrates the need for
8 the Commission to have an evidentiary hearing on the IRP
9 methodology's ability or lack thereof to accurately
10 estimate avoided cost rates should you decide to lower
11 the eligibility cap, because if as we profess that the
12 IRP methodology is fatally flawed in doing so, if you
13 reduce the eligibility cap, you will have put in a
14 moratorium that will prevent all proj ects larger than 100
15 kW from access to accurate avoided cost rates, so I think
16 before you make that decision it would be incumbent upon
17 you to convene an evidentiary hearing to address that
18 issue.
19 COMMISSIONER SMITH: Thank you,
20 Mr. Richardson. Mr. Andrea.
21 MR. ANDREA: Thank you, and I apologize
22 for opening up that bunny trail. I was just hoping to
23 provide some assistance to the Commission on the actual
24 model. The other two points I want to hit and I'll do it
25 very quickly, I very much appreciate Mr. Miller's and his
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1 client's attempt to try and solve the issue. The
2 recogni tion of the issue and thinking imaginatively to
3 try and find a resolution is very much appreciated.
4 Avista is very concerned with their
5 proposal.It keeps the 10 average megawatt cap and adds
6 some additional conditions. The way it's written I think
7 it's all addi ti ve; in other words, the proposal is only
8 as strong as its weakest element and part of that element
9 is a demonstration of ownership, and what we know is that
10 the developers can be very imaginative at figuring out
11 ways to get around at least that particular element and
12 maybe others, everything from, you know, using legal
13 fictions of LOC' s to change the ownership or not having
14 ownership but having development fees.
15 There's probably a myriad of other ways in
16 order to get around those particular requirements and I
17 couldn't possibly -- I don't have the imagination to come
18 up with all of those, but if there's an economic
19 incenti ve, I'm sure that some will and that's why we
20 think the 100 kW is the right eligibility cap. It's
21 simple. It's not going to take a great deal of work by
22 this Commission or Staff or the utilities to implement or
23 enforce or monitor or question. It will hopefully
24 fulfill the purposes of PURPA while protecting our
25 ratepayers, and the final issue that I do want to hit
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1 just briefly is, again, Mr. Richardson's statement about
2 utili ties think PURPA is a bad thing.
3 We certainly have concerns about paying
4 too much for PURPA power. We certainly have concerns
5 about having to take power when we're long and we don't
6 need it, especially in today' s environment where at
7 certain times of the year rates are zero or even
8 negati ve, so yes, we do have concerns with PURPA, but we
9 don't think of PURPA as a bad thing. That is just not
10 true. Again, as I stated earlier, we take our PURPA
11 obligation very seriously. We will negotiate with the
12 PURPA developers in good faith and we do not think of
13 PURPA as a bad thing, so I appreciate the Commission 's
14 time and consideration and I'm open to any questions if
15 you have any. Thank you.
16 COMMISSIONER SMITH: Mr. Kaufmann.
17 MR. KAUFMANN: Thank you, Madam Chairman.
18 I also would like to address three points briefly in my
19 rebuttal. The first point goes to Mr. Richardson's
20 assertion that relying on the IRP methodology and the
21 proprietary models would violate PURPA because those
22 models do not model the capacity value of QF proj ects.
23 PacifiCorp uses a GRID model, GRID is an acronym,
24 G-R-I-D, to model operating costs, variable operating
25 costs, of a system with and without a QF, a proposed QF,
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1 addition. PacifiCorp uses an additional component,
2 partial displacement model, to estimate the incremental
3 capaci ty value of the QF. Together those models value
4 both the energy and the capacity of a QF.
5 My second point addresses a comment
6 Mr. Williams made that the Cedar Creek proj ect' s IRP
7 methodology yielded a first year price of $37.00 per
8 megawatt-hour. I don't dispute that. I don't know that
9 to be true, but that sounds plausible. What I think that
10 reflects is that with large QF projects, the addition of
11 a single project is not incremental and you heard IPUC
12 Staff member Kristine Sasser mention that as large
13 amounts of QF capacity and energy come onto the utility's
14 system, the incremental value of that energy can go to
15 zero.
16 The IRP methodology for the Cedar Creek
17 project did yield a levelized cost or price of $57.00
18 over a 20-year levelized basis and if that price is
19 different from Idaho or Avista, it probably should be
20 because Idaho and Avista have different systems,
21 different system costs and different capacity needs.
22 My final point addresses the single
23 qualifying facility requirement proposal put forth by the
24 Conservation League/RNP and explained very eloquently by
25 Mr. Miller. I have looked through that as you asked me
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1 in my direct whether we had an opinion and I have a
2 couple of comments. First is that this rule does ignore
3 a one-mile separation criterion and that criterion is
4 something that the Commission has recognized and used in
5 the past and I think that it serves a useful purpose, and
6 as to the comments by Mrs. Davis regarding the concerns
7 of North Side Canal, I note that FERC doesn't literally
8 apply the one-mile rule in the case of hydro proj ects.
9 If the Commission were to adopt the FERC
10 application of the one-mile rule, I don't think it would
11 necessarily be a concern for North Side Canal Company. I
12 think the one-mile rule has value or a bigger radius for
13 that matter, and then also with respect to item 4 on this
14 list, in order to be a 10 average megawatt QF or greater,
15 one of the criteria is item 4, shares common
16 interconnection or control, communications, and operation
17 facilities, so it's A or Band C and D, so if any of
18 those aren't satisfied, then the QF is not disqualified
19 under this test.
20 My point here is that I have concerns that
21 this particular language would not filter the
22 disaggregated wind projects that PacifiCorp did execute
23 PURPA contracts with in 2010. I do like the idea that
24 the QF would have a responsibility to warrant that it has
25 complied with whatever requirement the Commission might
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1 establish if it went this route because I think that
2 will -- I do think the developer's investors will bring a
3 level of scrutiny to this test that will help it be
4 applied in a rigorous manner, but I think that this
5 proposal while interesting has not had the benefit of
6 rigorous cross-examination in order to make sure that it
7 would in fact accomplish the goals for which it's
8 intended.
9 I, therefore, would reiterate
10 PacifiCorp/Rocky Mountain Power's position that in the
11 interim the best way to protect its ratepayers' interests
12 would be to reduce the cap uniformly applicable to on and
13 off-system QFs to 100 kilowatts as required by federal
14 law and that that would give the Commission ample time to
15 consider all its options for a long-term solution.
16 This has been my first opportunity to
17 appear before the Commission. I hope it's not my last.
18 I'd like to say thank you, it's been a privilege and this
19 concludes my remarks.
20 COMMISSIONER SMITH: I actually do have a
2 i question for each of you. Having been through this once
22 before and having been dismayed by the length of time it
23 took to come to a resolution, I noted with great concern
24 Mr. Miller's comments that he doesn i t see any commitment
25 on the part of the utili ties of resources with regard to
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1 the IRP methodology, nor any commitment on the part of
2 the utili ties to complete any necessary review, which I
3 think we all agree there's questions that need to be
4 addressed and answered in a timely fashion, recognizing
5 that others have money expended and on the table and our
6 usual regulatory time frame may not be beneficial in that
7 case, so I guess I would appreciate knowing if any of you
8 can make any commitments with regard to that or identify
9 what you think is a time frame for a timely review and
10 you can even take 30 seconds to think about it if you'd
11 like.12 Mr. Miller.
13 MR. MILLER: Madam Chairman, while the
14 utili ty companies are conferring, even though it's
15 perhaps out of place, I would just like to make sure that
16 everyone understands that the ICL/RNP proposal is a
17 discussion draft. RNP /ICL and myself are more than
18 willing to consider and discuss any improvements that
19 could be done to meet party concerns in the hopes of
20 finding a middle ground that will leave everyone solemn
21 but not openly mutinous.
22 COMMISSIONER SMITH: A quote which I often
23 use and deeply appreciate and that's how I viewed your
24 proposal, Mr. Miller. I was appreciative of it, but
25 recognize that it probably needed review.
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1 Mr.Kaufmann,are you ready?
MR.KAUFMANN:Yes,Madam Chairman.You
asked whether the utili ties are willing to represent that
they would commit resources to implement the IRP
methodology,I've conferred with Bruce Griswold,he's the
2
3
4
5
6 director of origination at PacifiCorp/Rocky Mountain and
7 he i s reminded me that Oregon uses the IRP methodology to
8 model costs for large QFs, that is, QFs with nameplate 10
9 megawatts and above in Oregon and it has a scheduled
10 tariff and that tariff has time lines that mandate how
11 quickly the utility responds.
12 The applicant has an initial burden to
13 provide the information necessary to model the proj ect.
14 Then the utility has an obligation to declare that it's
15 correct or that it's complete or if not complete to
16 identify missing items within two weeks. Then when the
17 QF responds, the utility has 30 days to model the proj ect
18 and to present the indicative pricing proposal to the QF.
19 PacifiCorp is prepared to make that same commitment in
20 terms of timeliness of processing Idaho QF applications
21 under the IRP methodology.
22 COMMISSIONER SMITH: How about the other
23 response?
24 MR. KAUFMANN: I'm sorry?
25 COMMISSIONER SMITH: How long to undertake
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1 the review that is necessary in Idaho, what's a timely
2 processing of all the issues? Do you want to think about
3 that for a minute while I go to Mr. Walker?
4 MR. WALKER: Thank you, Madam Chairman.
5 You know, Idaho Power would obviously, would commit
6 whatever resources are necessary to comply with the
7 Commission's orders and directives as far as processing
8 IRP-based methodologies, PURPA proj ects, what have you.
9 As far as a reasonable time for any further proceedings
10 to take place, you know, once again, the Company would
11 commit whatever resources are necessary to meet the
12 Commission's expectations of that. As far as any
13 specific time period would be nothing more than a guess
14 at this point. Many of those things are not solely up to
15 Idaho Power or the utili ties. They're up to the
16 participants in this proceeding, the participants in the
17 further proceedings and --
18 COMMISSIONER SMITH: I recognize that, but
19 I guess what I'm trying to get at is if we said 30 days,
20 do you think that's reasonable?
21 MR. WALKER: I don't.
22 COMMISSIONER SMITH: Okay; so if we said
23 60 days, is that reasonable?
24 MR. WALKER: No.
25 COMMISSIONER SMITH: If we said 90 days,
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1 is that reasonable?
2 MR. WALKER: I don't think 90 days is even
3 a reasonable time that --
4 COMMISSIONER SMITH: So if we said 180
5 days, is that reasonable?
6 MR. WALKER: I think if you start talking
7 about months rather than days, you're getting closer to
8 the--
9 COMMISSIONER SMITH: That's six months. I
10 know, it's very quick in regulatory time; right?
11 MR. WALKER: It is.
12 COMMISSIONER SMITH: But it's not very
13 quick if you're somebody with money on the line.
14 MR. WALKER: I think the magnitude and
15 importance of the issues, you know, approaches that of a
16 rate proceeding and possibly the statutory time period
17 set out to process and conduct a rate proceeding in front
18 of this Commission could be a good measure --
19 COMMISSIONER SMITH: Something less than a
20 year.
21
22
MR. WALKER: -- of reasonableness.
COMMISSIONER SMITH: Mr. Andrea, did you
23 want to weigh in?
24.25
MR. ANDREA: Yes, thank you. I think it's
a very difficult question to ask. I think it's a very
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14
1 appropriate question to ask, but a very difficult
2 question to ask how long will it take. Like Idaho Power,
3 Avista will commit the resources to do this in as short a
4 time frame as reasonably possible.I think a year is
5 probably in the ball park, but the other point I really
6 want to make on this, it's in our interests to get this
7 resol ved not only timely but right. The grandfathering
8 issue continues to be out there. We hope that at least
9 gets solved in the interim while we solve the larger
10 problem, but we have all spent a lot of time and effort
11 on these issues over the years and it's in all of our
12 interests to try and resolve it in as timely a way as we
possibly can and we will certainly commit to do that to
the extent that we can wi thin the bounds of
15 reasonableness.
16
17
COMMISSIONER SMITH: Mr. Kaufmann.
MR. KAUFMANN: I've consul ted with Bruce
18 Griswold and he's been through this process in Oregon and
19 other places, including in Idaho in 2005, and he also
20 thinks that a year is probably realistic, but we
21 acknowledge that the interim relief that the utili ties
22 have requested, the balance of interests and harms in
23 that may evolve over the year. The Commission could
24 revisi t that before the proceedings were completed or at.25 least could consider it, depending on the progress and
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109 COLLOQUY
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1 what comes to light. I think we want to be ambitious in
2 a schedule, but also acknowledge reality to an extent,
3 too, that this is a complex process.
4 MR. RICHARDSON: Madam Chairman?
5 COMMISSIONER SMITH: I agree and nobody
6 wants this to happen more than I having thought it had
7 happened in the past and then being proved wrong.
8 Mr. Richardson.
9 MR. RICHARDSON: Madam Chairman, thank
10 you, if I would weigh in on this question. The case is
11 already three months old and we i ve had what is in effect
12 a moratorium on new proj ects. New developers are frozen
13 in their tracks as we speak when they look at Idaho. A
14 year is a lifetime. The industry will be dead at the end
15 of a year.
16 COMMISSIONER SMITH: Well, I know it took
17 us, what, two years last time, so one year is half of
18 that time and the industry doesn't look dead right now.
19 Mr. Williams.
20 MR. WILLIAMS: Madam Chair, this
21 Commission can process a major rate case for a utility as
22 required by statute in six months as I think that the
23 Commission could likewise process this case.
24
25
COMMISSIONER SMITH: Your confidence in us
is deeply appreciated --
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21
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24.25
1 MR. WILLIAMS: And well founded.
2 COMMISSIONER SMITH: I don't know if I'd
3 add that. Other Commissioners have any comments? I want
4 to thank everyone for your participation today,
5 especially those who did it by phone. I appreciate
6 everyone's collegial and brief points. It's a very
7 difficul t issue with emotional overtones and we
8 understand its importance to everybody in the room and we
9 appreciate your participation. Thank you, Connie, and
10 we'll get out an Order as soon as we can. Thank you.
11 We i re adj ourned.
12 (The Hearing adjourned at 1: 05 p.m.)
13
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1 AUTHENTICATION
2
3
4 This is to certify that the foregoing
5 proceedings held in the matter of the joint petition of
6 Idaho Power Company, Avista Corporation, and PacifiCorp
7 dba Rocky Mountain Power to address avoided cost issues
8 and to adj ust the published avoided cost rate eligibility
9 cap, commencing at 9:30 a.m., on Thursday, January 27,
10 2011, at the Commission Hearing Room, 472 West Washington
11 Street, Boise, Idaho, is a true and correct transcript of
12 said proceedings and the original thereof for the file of
13 the Commission.
14
15
16
19
ClfdthlL_¿;___
CONSTANCE S. BUCY
Certified Shorthand Repor
17
18
20
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112 AUTHENTICATION