20120827Volume II.pdf

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RECEtVED
BEFORE THE IDAHO PUBLIC UTILITIES COMMftI*t*27 FM 12:' t
UL: ('r
IN THE MATTER OF THE COMMISSION'S )UTILI
REVIEW OF PURPA QF CONTRACT ) CASE NO.
PROVISIONS INCLUDING THE ) GNR-E-11-03
SURROGATE AVOIDED RESOURCE (SAR)
AND INTEGRATED RESOURCE PLANNING ) TECHNICAL
(IRP) METHODOLOGIES FOR ) HEARING
CALCULATING PUBLISHED AVOIDED
COST RATES.
HEARING BEFORE
COMMISSIONER MARSHA H. SMITH (Presiding)
COMMISSIONER MACK A. REDFORD
COMMISSIONER PAUL KJELLANDER
~ Av
PLACE: Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE: August 7, 2012
VOLUME II - Pages 42 263
I POST OFFICE BOX 578
BOISE, IDAHO 83701
208-336-9208
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HEDRICK .
COURT REPORTING
4/r4iee 1978
App E A RAN C ES
For the Staff: KRISTINE A. SASSER, Esq.
Deputy Attorney General
472 West Washington
Boise, Idaho 83702
For Idaho Power Company:
For Avista Corporation:
For PacifiCorp dba Rocky
Mountain Power:
For Idaho Conservation
League:
For Idaho Wind Partners I,
LLC:
For The Northwest and
Intermountain Power
Producers Coalition;
Grand View Solar II;
The Board of County
Commissioners of Adams
County, Idaho; J. R. Simplot
Company; Exergy Development
Group of Idaho, LLC; and
Clearwater Paper Corporation:
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DONOVAN E. WALKER, Esq.
and JASON B. WILLIAMS, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
MICHAEL G. ANDREA, Esq.
Avista Corporation
1411 East Mission Avenue
Spokane, Washington 99202
DANIEL E. SOLANDER, Esq.
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
BENJAMIN J. OTTO, Esq.
Idaho Conservation League
710 North Sixth Street
Boise, Idaho 83702
GIVENS PURSLEY, LLP
by DEBORAH E. NELSON, Esq.
601 West Bannock Street
Boise, Idaho 83702
RICHARDSON & O'LEARY, PLLC
by PETER J. RICHARDSON, Esq.
and GREGORY M. ADAMS, Esq.
Post Office Box 7218
Boise, Idaho 83707
For Renewable Northwest McDEVITT & MILLER, LLP
Project; Idaho Windfarms, by DEAN J. MILLER, Esq.
LLC; and Ridgeline Energy, 420 West Bannock Street
LLC: Boise, Idaho 83702
HEDRICK COURT REPORTING
P. 0. BOX 578, BOISE, ID 83701
For Mountain Air Projects, UDA LAW FIRM, PC
LLC: by Michael J. Uda, Esq.
7 West Sixth Avenue, Suite 4E
Helena, Montana 59601
For Renewable Energy WILLIAMS BRADBURY, PC
Coalition and Dynamis by RONALD L. WILLIAMS, Esq.
Energy, LLC: 1015 West Hays Street
Boise, Idaho 83702
For Twin Falls Canal Company, CAPITOL LAW GROUP, PLLC
North Side Canal Company, by C. THOMAS ARKOOSH, Esq.
Big Wood Canal Company, and 205 North Tenth Street,
American Falls Reservoir Fourth Floor
District No. 2: Boise, Idaho 83702
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HEDRICK COURT REPORTING APPEARANCES
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WITNESS EXAMINATION BY PAGE
Thomas Tanton Prefiled Testimony 47
(Public)
Clint Kalich Mr. Andrea (Direct) 53
(Avista) Prefiled Direct 55
Prefiled Rebuttal 89
Mr. Walker (Cross) 108
Mr. Solander (Cross) 109
Mr. Otto (Cross) 110
Mr. Richardson (Cross) 113
Mr. Uda (Cross) 166
Mr. Arkoosh (Cross) 170
Ms. Sasser (Cross) 178
Commissioner Kjellander 179
Mr. Andrea (Redirect) 180
Brian Dickman Mr. Solander (Direct) 182
(Rocky Mountain Power) Kelcey Brown Prefiled Direct 184
Prefiled Rebuttal 197
Mr. Walker (Cross) 209
Mr. Andrea (Cross) 210
Ms. Sasser (Cross) 211
Paul Clements Mr. Solander (Direct) 214
(Rocky Mountain Power) Prefiled Direct 216
Prefiled Rebuttal 226
Mr. Otto (Cross) 235
Mr. Richardson (Cross) 242
Mr. Uda (Cross) 256
Mr. R. Williams (Cross) 258
Mr. Arkoosh (Cross) 261
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HEDRICK COURT REPORTING
P. 0. BOX 578, BOISE, ID 83701
INDEX
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NUMBER
EXH I B ITS
PAGE
For Avista Corporation:
101 Response to Avista's First Production Premark
Request No. 4, 8 pgs Admit 107
102 Response to Avista's First Production Premark
Request No. 1, 2 pgs Admit 107
103 Response to Avista's First Production Premark
Request No. 2, 3 pgs Admit 107
For Rocky Mountain Power:
201 Technical Appendix, 5 pgs Premark
Admit 209
202 Rocky Mountain Power Electric Service Premark
Schedule No. 38, 7 pgs Admit 235
For Clearwater Paper Corporation, et al:
509 IPUC Order No. 30892, 2 pgs Mark 118
510 Avista Corporation 2011 Electric IRP, Mark 132
Chapter 2, 10 pgs
511 Pacific Northwest Regional Resource Mark 137
Adequacy Assessment, 15 pgs
For Energy Integrity Project:
2001 Thomas Tanton Curriculum Vitae, 4 pgs Premark
Admit 50
HEDRICK COURT REPORTING EXHIBITS
P. 0. BOX 578, BOISE, ID 83701
BOISE, IDAHO, TUESDAY, AUGUST 7, 2012, 9:00 A.M.
COMMISSIONER SMITH: Good morning, ladies and
gentlemen. This is the time and place set for a hearing before
the Idaho Public Utilities Commission in the matter of the
Commission's review of PURPA QF contract provisions including
the surrogate avoided resource and integrated resource planning
methodologies for calculating published avoided cost rates.
It's further identified as Case No. GNR-E-11-03.
For those of you who may not be familiar with the
Commission, my name is Marsha Smith, I'm one of the
Commissioners, and I'll be conducting these hearings. To my
left is Commissioner Paul Kjellander, who is also the president
of the Commission; and to my right is Commissioner Mack
Redford. The three of us are the State Public Utilities
Commission and the people who will be making a determination in
this matter.
We'll begin today by taking the appearances of
the parties, and we'll start with you, Mr. Walker.
MR. WALKER: Thank you, Madam Chair. Donovan
Walker on behalf of Idaho Power.
MR. J. WILLIAMS: Good morning, Madam Chair,
Commissioners. Jason Williams on behalf of Idaho Power.
COMMISSIONER SMITH: Okay.
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Mr. Andrea.
MR. ANDREA: Good morning, Madam Chair,
Commissioners. Michael Andrea on behalf of Avista Corporation.
COMMISSIONER SMITH: Thank you.
Kris.
MS. SASSER: Kristine Sasser, representing
Commission Staff.
COMMISSIONER SMITH: Mr. Solander.
MR. SOLANDER: Good morning. Daniel Solander on
behalf of Rocky Mountain Power.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: There we go. Benjamin Otto on behalf
of the Idaho Conservation League.
MR. KEN MILLER: Good morning, Commissioners.
Ken Miller on behalf of the Snake River Alliance.
MR. RICHARDSON: Good morning, Madam Chairman.
This is Peter Richardson -- oop, sorry.
COMMISSIONER SMITH: Wait a minute.
MS. NELSON: Good morning. Deborah Nelson on
behalf of Idaho Wind Partners.
COMMISSIONER SMITH: Okay.
MR. RICHARDSON: Madam Chairman, Peter Richardson
with the firm Richardson & O'Leary. We've entered appearances
here on behalf of the Northwest and Intermountain Power
Producers Coalition, Grand View Solar, and the Board of County
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Commissioners of Adams County. We're appearing this morning on
behalf of -- jointly on behalf of the J. R. Simplot Company,
Exergy Development Group of Idaho, and Clearwater Paper
Corporation.
And to my right is Greg Adams with the firm
Richardson and O'Leary; and behind me is Kristine -- Kristie
Cromwell, who's a summer clerk with us who will be assisting us
today.
COMMISSIONER SMITH: Thank you, Mr. Richardson.
Mr. Miller.
MR. MILLER: Thank you, Madam Chairman. Dean J.
Miller of the firm McDevitt and Miller. I've entered three
appearances: One on behalf of the Renewable Northwest Project,
one on behalf of Idaho Windfarms, and one on behalf of
Ridgeline Energy, LLC.
I'd also like to introduce to the Commission
Mr. Willem Van der Ven of Ridgeline, who is a vice president
with Ridgeline and responsible for the day-to-day operations of
the Rockland project.
COMMISSIONER SMITH: Thank you, Mr. Miller.
MR. UDA: Madam Chair, all the way from Helena,
Montana, Michael Uda, Uda Law Firm, out of Montana. I'm here
representing Mountain Air Projects.
COMMISSIONER SMITH: Thank you, Mr. Uda.
Mr. Williams.
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MR. R. WILLIAMS: Madam Chair, Ronald L.
Williams of Williams Bradbury on behalf of two parties in this
case: One is the Renewable Energy Coalition, and the other is
Dynamis Energy, LLC.
MR. ARKOOSH: Madam Chairman, Tom Arkoosh with
Capitol Law Group, and I've entered appearances for Twin Falls
and North Side and Big Wood Canal Companies, and American Falls
Reservoir District No. 2.
COMMISSIONER SMITH: Long time, no see,
Mr. Arkoosh.
MR. ARKOOSH: Yes, ma'am. Not since the '80s,
ma'am.
COMMISSIONER SMITH: Well, welcome back.
MR. ARKOOSH: Thank you.
COMMISSIONER SMITH: Let me see. Is there anyone
else who needs to make an appearance who hasn't? Is
Mr. Sorenson --
MR. BILL PI5KE: I'm Bill Piske on behalf of
Interconnect Solar Development.
COMMISSIONER SMITH: Is Mr. Sorenson here for
Birch Power? Okay.
MR. R. WILLIAMS: Madam Chairman, Mr. Sorenson is
not here, but he will be here on Thursday morning.
COMMISSIONER SMITH: Okay, thank you. I think
that must be it.
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HEDRICK COURT REPORTING COLLOQUY
P. 0. BOX 578, BOISE, ID 83701
I have one preliminary matter: As you know, the
Energy Integrity Project was an Intervenor in this proceeding,
and filed the testimony of Thomas Tanton with Exhibit 20- --
2001; however, they do not have legal counsel and, therefore,
could not present their testimony without legal counsel
according to the Rules of Procedure of the Commission.
Therefore, while we haven't scheduled a time for taking public
testimony, I have offered and they have accepted the
opportunity to have that testimony viewed as a public comment
in this proceeding. And the Commission will have that entered
into the record as a public comment by the Energy Integrity
Project.
Is there any objection to proceeding in that
manner? Seeing none, it is so ordered.
(The following prefiled testimony of
public witness Mr. Thomas Tanton is spread upon the record.)
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HEDRICK COURT REPORTING COLLOQUY
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•
1 INTRODUCTION
2 Q. Please state your name and business address.
3 A. My name is Thomas Tanton and my business address is 4390 Indian Creek
4 Road, Lincoln, California 95648.
5 Q. By whom are you employed and in what capacity?
6 A. I am President of T 2 & Associates, a firm located in Lincoln, California,
7 which provides consulting services to the energy and technology industries.
8 Q. Please describe your educational background and work experience.
9 A. 12 & Associates are active primarily in the area of renewable energy and
10 interconnected infrastructures, analyzing and providing advice on their impacts on energy
11 prices, environmental quality and regional economic development. I have 38 years direct
• 12 and responsible experience in energy technology assessment, resource planning, electric
13 grid integration and infrastructure development.
14 As the General Manager at the Electric Power Research Institute (EPRI),
15 from 2000 to 2003,1 was responsible for the overall management and direction of
16 collaborative research and development programs in renewable and hydroelectric
17 generation technologies, integrating technology, market infrastructure, and public policy.
18 From 2003 through 2007, I was Senior Fellow and Vice President of the Houston based
19 Institute for Energy Research. I was also a Senior Fellow in Energy Studies with the
20 Pacific Research Institute until 2010. Until 2000,1 was the Principal Policy Advisor with
21 the California Energy Commission (CEC) in Sacramento, California. I began my career
22 there in 1976. I developed and implemented policies and legislation on energy and
23 environmental issues of importance to California, and U.S. and International markets,
[I: 47
1 including electric restructuring, gasoline and natural gas supply and pricing, energy
2 facility siting and permitting, environmental issues, power plant siting, technology
3 development, and transportation. I completed the first assessment of environmental
4 externalities used in regulatory settings, placing a monetary value on environmental
5 pollutant emissions. I held primary responsibility for resource planning, comparative
6 economic analysis, environmental assessment of new technologies, and the evaluation of
7 alternatives under state and federal environmental law. I served as Guest Lecturer for the
8 Master in Environmental Science program at California State University Sacramento
9 (CSUS), lecturing on power plant and electric grid technologies and their comparative
10 environmental impacts.
11 In my role as Principal Policy Advisor at the California Energy Commission, I
is 12 evaluated power plant applications for certification, including environmental, economic
13 and reliability considerations.
14 I have extensive experience with electricity resource planning and resource
15 integration, including use of dispatch modeling to evaluate impacts on customer price and
16 grid reliability from the addition of specific or generic resources to a grid.
17 My curriculum vitae is provided as Exhibit No. 2001 hereto and incorporated by
18 reference herein.
19 Q. What is the purpose of your testimony in this matter?
20 A. I have been asked by Energy Integrity Project to give recommendations
21 relevant to the Idaho Public Utilities Commission's ("Commission") current review of
22 the methodology for computing avoided costs in PURPA implementation.
.

TANTON, DI -3
Energy Integrity Project
1 I. Recommendations
2 Q. Could you please state your recommendations?
3 A. I appreciate the PUC's efforts to adopt improved methods for determining
4 the avoided costs delivered by Qualifying Facilities. After reviewing current and
5 proposed methodologies for determining the energy component of the IRP avoided
6 cost, I believe that a significant component has been overlooked. The overlooked
7 component is that the integration of QF generation into the electric system is not
8 perfectly efficient. For a variety of reasons, the quantity of fossil fuel saved by each
9 MWh of QF generation is likely to be less than the quantify of fossil fuel that would
10 have been required to replace that MWh by the next marginal increment of non-QF
11 generation.
• 12 I recommend that the PUC change the IRP avoided cost calculation by
13 taking the actual fuel savings achieved by each QF into account. I believe the actual
14 fuel savings could be calculated by re-running the chronological dispatch for the
15 contract year with and without the QF, and taking the difference in total fuel
16 consumption. Other State's Commissions have used this method in the past and more
17 accurately accounts for the value of capacity and of energy.
18 Side-by-side chronological dispatch should be benchmarked with actual
19 recent (from the past year) recorded performance of generators on the grid and actual
20 recent recorded loads and load profiles. Such comparisons should be done for each
21 contract year, or small combination of years, and for each QF connecting to the grid.
22 Alternatively, small groupings of QFs, depending on their aggregate capacity and
23 energy, could reduce computational requirements.
49 TANTON, DI -4
Energy Integrity Project
I Q. Does this complete your testimony at this time?
2 A. Yes, it does.
Li
50 TANTON, DI- S
Energy Integrity Project
(The following proceedings were had in
open hearing.)
(Energy Integrity Project Exhibit No.
2001, having been premarked for identification, was admitted
into evidence.)
COMMISSIONER SMITH: Are there any other
preliminary matters that need to come before the Commission
before we begin with the presentation? Mr. Williams.
MR. R. WILLIAMS: Madam Chair, I have a couple of
constraints with a couple of witnesses.
First of all, Mr. Looper can be here anytime
today or tomorrow but is conflicted on Thursday, and so if he
could be done by Wednesday night, that would be -- he would
appreciate that.
Secondly, Mr. Sorenson said while he could come
over on Wednesday at noon, it would be more convenient for him
if his appearance could be some day (sic) on Thursday, in which
he would then drive over from Idaho Falls Thursday morning
early.
COMMISSIONER SMITH: I don't see any problem
accommodating that, Mr. Williams.
MR. ARKOOSH: Madam Chairman, I have a similar
difficulty with Mr. Hansten, who is the North Side Canal
Company representative. He can't be here until Thursday
morning because of a family health matter.
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HEDRICK COURT REPORTING COLLOQUY
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COMMISSIONER SMITH: All right. Any other
scheduling concerns?
MR. WALKER: Madam Chair, Idaho Power has a
witness, William Hieronymus, who is in from out of town and
available today. We would request, if we could possibly take
him out of order even if required, to get his testimony on
today.
COMMISSIONER SMITH: Okay. We'll do what we can.
All right, no other scheduling?
Any other preliminary matters to come before the
Commission today?
MR. WALKER: Madam Chair.
COMMISSIONER SMITH: Mr. Walker.
MR. WALKER: If I could clarify the Commission's
intent with regard to the number of times to call witnesses to
the stand, if we could -- if it's the Commission's intent to
admit both direct and rebuttal with one appearance of the
witness on the stand or -- that would be our preference.
COMMISSIONER SMITH: Mr. Walker, I deem that to
be the prerogative of the attorney presenting the witnesses.
If it's your choice to do your rebuttal with your direct, you
may do so. If it's your choice to reserve your rebuttal for
later, that's fine. So whatever you choose to do will be
fine.
Okay, seeing nothing else, it's my intention to
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HEDRICK COURT REPORTING COLLOQUY
P. 0. BOX 578, BOISE, ID 83701
start with Mr. Andrea's witness and move to Mr. Solander, and
then Mr. Walker. Is there any objection to that?
If you have a microphone that has a little red
light and it says "touch" on it, if the red light is on, your
mic is hot and we will hear your papers rustle, we will hear
your side comments, whoever you're making them to. So if you
don't want to be heard -- and, frankly, we don't want to hear
that -- please punch the touch button so the light goes off and
your microphone isn't live.
The two tables on the east side of the room have
mikes that aren't part of our system and they don't have an off
button, so we have disconnected those so that we don't hear
everything that happens over there all day. And those people
can either speak loudly, or they can plug them in when they
need to talk and then unplug them when they don't, aren't
speaking. So we apologize if that's inconvenient, but that is
what we needed to do to accommodate the size of the group that
we have.
So, nothing further. Let's start with you
Mr. Andrea.
MR. ANDREA: Thank you, Madam Chair. Avista
calls Clint Kalich.
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HEDRICK COURT REPORTING COLLOQUY
P. 0. BOX 578, BOISE, ID 83701
CLINT KALICH,
produced as a witness at the instance of Avista Corporation,
being first duly sworn, was examined and testified as follows:
DIRECT EXAMINATION
BY MR. ANDREA:
Q. Could you please state your name for the record,
please?
A. Clint Kalich.
Q. And who are you employed by?
A. Avista Corporation.
Q. And what's your position at Avista?
A. I manage the resource planning and power supply
analyses group.
Q. Are you the same Clint Kalich that provided the
direct testimony of Clint Kalich on behalf of Avista
Corporation filed in this proceeding on January 31, 2012?
A. Yes, I am.
Q. And are you the same Clint Kalich that provided
the rebuttal testimony of Clint Kalich on behalf of Avista
Corporation filed on June 29, 2012, and corrected by an errata
submitted on August 7, 2012?
A. Yes.
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Q. And do you sponsor Exhibits 101, 102, and 103 to
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HEDRICK COURT REPORTING KALICH (Di)
P. 0. BOX 578, BOISE, ID 83701 Avis t a
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your rebuttal testimony?
A. Yes.
Q. Is the direct and rebuttal testimony the same
testimony you would provide today?
A. Yes, it is.
MR. ANDREA: Madam Chair, Commissioners, I ask
that the direct testimony of Clint Kalich and the rebuttal
testimony of Clint Kalich be spread upon the record as if fully
read therein, and Mr. Kalich is available for cross.
COMMISSIONER SMITH: Okay. And his exhibit,
would you identify his exhibit?
MR. ANDREA: Yes, Madam Chair. Exhibits 101,
Exhibits 102, and 103.
COMMISSIONER SMITH: Okay. If there is no
objection, we will spread the prefiled direct and rebuttal
testimony of Mr. Kalich upon the record as if it had been read,
and admit Exhibits 101, 102, and 103.
(The following prefiled direct and
rebuttal testimony of Mr. Kalich is spread upon the record.)
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HEDRICK COURT REPORTING KALICH (Di)
P. 0. BOX 578, BOISE, ID 83701 Avista
10
LI
.
1 I. INTRODUCTION AND TESTIMONY OVERVIEW
2 Q. Please state your name, the name of your employer, and your business
3 address.
4 A. My name is Clint Kalich. I am employed by Avista Corporation
5 ("Avista") at 1411 East Mission Avenue, Spokane, Washington.
6 Q. Please state your educational background and professional
7 experience.
8 A. I graduated from Central Washington University in 1991 with a Bachelor
9 of Science Degree in Business Economics. Shortly after graduation, I accepted an
10 analyst position with Economic and Engineering Services, Inc. (now EES Consulting,
11 Inc.), a northwest management-consulting firm located in Bellevue, Washington. While
12 employed by EES, I worked primarily for municipalities, public utility districts, and
13 cooperatives in the area of electric utility management. My specific areas of focus were
14 economic analyses of new resource development, rate case proceedings involving the
15 Bonneville Power Administration, integrated (least-cost) resource planning, and demand-
16 side management program development.
17 In late 1995, I left Economic and Engineering Services, Inc. to join Tacoma
18 Power in Tacoma, Washington. I provided key analytical and policy support in the areas
19 of resource development, procurement, and optimization, hydroelectric operations and re-
20 licensing, unbundled power supply rate-making, contract negotiations, and system
21 operations. I helped develop, and ultimately managed, Tacoma Power's industrial market
22 access program serving one-quarter of the company's retail load.
Case No. GNR-E-1 1-03
55 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 2 of 35
1 In mid-2000 I joined Avista and accepted my current position assisting the
2 Company in resource analysis, dispatch modeling, resource procurement, integrated
3 resource planning, and rate case proceedings. I have participated in proceedings before
4 the Commission since 2000, and cases surrounding PURPA beginning in 2002.
5 Q. Why are you providing testimony before the Commission today?
6 A. Avista wants to ensure that its customers receive fair value for the
7 electricity they purchase. This is the basic premise of Public Utility Regulatory Policy
8 Act (PURPA) law: utilities should pay no more than what they otherwise would for
9 Qualifying Facility (QF) deliveries of capacity and energy (i.e., the utilities actual
10 avoided costs). A misalignment between the prices utilities pay for QF power and the
11 utilities' actual avoided costs still exists in some cases in Idaho. Recent QF wind
12 development history illustrates how important it is for rates paid to QFs to reflect the
13 purchasing utilities' actual avoided costs. My testimony provides a framework under
14 which the rates paid for QF power under PURPA cannot greatly exceed the utilities'
15 actual avoided costs and, therefore, the value customers receive for such power.
16 Q. Please provide an overview of your testimony?
17 A. My testimony will first provide some background discussions on topics
18 Avista wishes to highlight in this hearing. These include:
19 1) principles of avoided cost,
20 2) key avoided costs concepts - energy and capacity,
21 3) defining utility need,
22 4) valuing power output during periods of utility deficit and surplus, and
Case No. GNR-E-1 1-03 56 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 3 of 35
1 5) bifurcation of rates to reflect capacity and energy costs avoided by the purchase of
2 QF power.
3 After providing some background, my testimony makes the following
4 recommendations:
5 1) continue limiting published rate eligibility for variable generators to 100 kW,
6 2) bifurcate all PURPA rate schedules into capacity and energy,
7 3) provide capacity payments only in those years where the utility is deficient,
8 4) during periods of utility energy surplus, PURPA rates should be discounted for
9 the transmission costs, including transmission losses, associated with re-selling
10 the surplus power into the market,
11 5) PURPA contracts should be signed no earlier than five years before commercial
12 operation; fixed prices should be made available no earlier than two years before
13 commercial operation,
14 6) PURPA contracts should retain meaningful liquidated damage and termination
15 provisions,
16 7) SAR gas prices should be updated annually for published rates using the Energy
17 Information Administration's Annual Energy Outlook, and
18 8) the Commission should not determine REC ownership in this docket.
19 III
20 III
21 III
22 III
23 III
Case No. GNR-E-1 1-03 57 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 4 of 35

. 1 II. AVOIDED COST BACKGROUND DISCUSSION
2 Principles of Avoided Costs

3 Q. Please provide a general discussion of PURPA and avoided costs as it
4 pertains to this proceeding.

5 A. PURPA was passed in 1978 to help create a market for non-utility electricity

6 supplies.' PURPA, and its associated regulations, obligates utilities to buy "energy and
7 capacity which is made available from a qualifying facility" at rates not exceeding the
8 incremental costs to the utility of electric energy and/or capacity which, but for the
9 purchase from the QF, the utility would generate itself or purchase from another source.2
10
.
10 The rates for such purchases "shall be just and reasonable to the electric consumer. . .
11 While the obligation to purchase is mandated by federal law, pricing and many of the
12 terms and conditions of PURPA contracts are left to the state. States have been given
13 wide discretion in setting the rates, terms, and conditions for PURPA contracts, but are
14 required "to put into effect.. . standard rates for purchases from qualifying facilities with a
15 design capacity of 100 kilowatts or less."4
16 In Idaho, the Idaho Public Utilities Commission (Commission) is responsible for
17 implementing PURPA. The Commission sets rates and methodologies for all QF
18 developers wishing to sell their output in the State of Idaho to one of the utilities
19 regulated by the Commission.
1 Today it can be argued that QF developers have adequate access to the marketplace absent the PURPA.
For example, utilities generally procure new long-term supplies of electricity through regulated or quasi-
regulated competitive acquisition processes that QF developers can bid into. Federal laws and regulations
also now obligate utilities to sell or build transmission capacity to/for 3 rd parties, enabling QF developers to
sell their output to other utility systems or at the major trading hubs.
2 18 C.F.R. § 292.101(b6) (defining "avoided costs").
18 C.F.R. § 292.304(a)(l)(i).
"18 C.F.R. § 292.304(c).
Case No. GNR-E-1 1-03 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page of 35

1 Q. Please expand on the definition of avoided cost.

2 A. Avoided cost is a complex concept, as the 33-year history of PURPA and its
3 implementation in Idaho shows. FERC regulations define avoided costs as meaning "the
4 incremental costs to an electric utility of electric energy or capacity or both which, but for
5 the purchase from the qualifying facility or qualifying facilities, such utility would
6 generate itself or purchase from another source."5 FERC allows for differentiation of the
7 avoided cost rate based on a number of factors, including consideration of: a) daily and

8 seasonal shaping, b) the ability of the utility to dispatch the resource, c) the demonstrated
9 reliability of the resource, d) the term, termination notice, and sanctions for non-
10 compliance, e) the extent to which outages can be usefully coordinated with utility needs,

11 f) the usefulness of the resource during system emergency, g) the reduction of fossil fuel

12 use, and h) line loss savings or costs attributable to the resource.6

13 A simplified interpretation of this provision is that customers should pay no more
14 for a QF purchase than a least-cost alternative to it. And further to this point, customers
15 should pay only an amount equal to the costs that they actually avoid by making the QF
16 purchase; in other words, if no costs are being avoided, the QF developer should not
17 receive compensation for its deliveries under PURPA.
18 Energy and Capacity Definitions

19 Q. How does one define "energy" in the context of PURPA?

20 A. PURPA does not specifically define energy. According to a March 2011
21 paper by the Pacific Northwest Utilities Conference Committee (PNUCC), energy
18 C.F.R. § 292.101(b)(6).
6 18 C.F.R. § 292.304(e).
Case No. GNR-E-1 1-03
January 31, 2012
Kalich, C. (Direct)
Avista Corporation
Page 6 of 35
1 "measures the quantity of electrical power (i.e., flow) over time."7 It is measured in watt-
2 -hours. In the northwest, energy is generally measured in average megawatts because it
3 measures average consumption over a period of time.
4 Q. What is the definition of "capacity" in the context of PURPA?
5 A. In contrast to energy, capacity measures the ability to produce power to
6 meet system load requirements.8 It is a generic term often requiring the use of a
7 descriptor, such as "nameplate" capacity or "net winter" capacity. In the context of
8 PURPA, many of the avoided cost considerations listed earlier in my testimony require
9 differing types of capacity.
10 An important concept for PURPA in Idaho is the on-peak capacity contribution of
11 a resource. In other words, the resource's ability to reliably generate during times of the
12 utility system's peak. Absent the ability to reliably generate during peak-period hours,
13 there are no avoided capacity costs because, notwithstanding the existence or non-
14 existence of the QF, the utility will need to build or otherwise acquire a resource to
15 generate during times of the utility system's peak. FERC has acknowledged this point in
16 its rules.9 Therefore, a QF that cannot be relied on to generate during times of system
17 peak does not avoid any utility capacity costs. It follows that a QF that cannot be relied
18 on to provide on-peak generation should not receive any payment for the capacity portion
19 of the PURPA avoided cost rate.
http://pnucc.org/documents/CapabilitiesofResourcesReportandMemoweb.pdf.
The "ability" to produce power, in the case of wind and other variable and fuel-limited renewables, also
means that the resource has fuel adequate to generate power during the peak system load requirement. • 18 C.F.R. § 292.304(eX2) states that the rate shall be based on: "the availability of capacity or energy
from a qualifying facility during the system daily and seasonal peak periods."
Case No. GNR-E-1 1-03 60 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 7 of 35
~ 0 1
Q. How should the on-peak contribution of a QF resource, and the level
2 of its capacity payment, be determined?
3 A. The contribution should be determined in a manner similar to how the
4 utility identifies the on-peak capacity contribution of its other resources. A first step is to
5 determine the expected, or average, on-peak contribution. For example, the QF
6 developer must supply a "12x24" matrix of its expected future deliveries as part of the
7 contracting process. This means the QF developer provides one estimated 24-hour shape
8 of power output for each calendar month. From this shape much can be learned. For
9 example, an irrigation canal hydroelectricity facility's 12x24 matrix will show clearly
10 that no generation is delivered to the utility during the winter months. So, in Avista's
11 case where on-peak capacity benefits are defined by winter output, an irrigation canal
~ 0 12 hydroelectricity facility is not able to generate during Avista' s winter peak and, therefore,
13 the capacity contribution is zero.
14 The analysis is more complicated if the utility system peaks during the summer
15 when the canal project is expected to generate at some level during peak load periods.
16 Capacity planning based on statistical averages, like the 12x24 matrix, has the potential
17 to compromise reliability because during approximately half of future contract years the
18 resource will not perform at the average level of capacity. A statistical approach to
19 quantifying a QF resource's capacity, similar to how the utility does its other capacity
20 planning, should be applied. Absent a long period of historical record to evaluate the
21 contribution, the QF resource should receive a capacity contribution based on levels for
22 similar resources identified by the utility in its Integrated Resource Plan (IRP).
.
Case No. GNR-E- 11-03 61 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 8 of 35
1 Q. Does this approach work for resources other than irrigation canal
2 hydro used in your example above?
3 A. Yes. For Avista's IRP the on-peak capacity contribution of each major
4 resource type is input into its Preferred Resource Selection Model (PRiSM). I
5 recommend that values from the IRP be used to set the on-peak capacity values in
6 PURPA contracts except possibly for wind where a small contribution might be used.
7 Based on Avista's IRP, the following on-peak contributions would be applied to QF
8 developer projects. 10 Contributions are reduced for operating reserves the utility is
9 obligated to provide as part of its membership in the Northwest Power Pool.
10 Table I - Avista On-Peak Capacity Contributions from 2011 IRP
11
0 12
Resource Contribution Resource Contribution
Canal Hydro 0% Solar 5%
Wind 0% Biomass 93%
13 Q. You mention that you might support a small on-peak contribution for
14 wind. What level will you support?
15 A. Without a geographically diversified portfolio of wind it is difficult to
16 assign any on-peak contribution value for wind. It is Avista's concern for maintaining
17 system reliability that it assigns no capacity value to wind in its IRP. This said, the
18 Northwest Power and Conservation Council (NPCC) uses a regional on-peak capacity
19 benefit of five percent. To be consistent with the NPCC, I will support a five percent on-
20 peak capacity contribution for wind for PURPA projects. However, Avista will continue
21 assigning wind a zero on-peak capacity value in its planning assessments, including the
Values represent winter on-peak contribution. For example, canal hydro operates during the spring and
summer months, with no output during the winter. Avista's wind rating is low due to the lack of wind
diversity in its portfolio.
Case No. GNR-E-1 1-03 62 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 9 of 35
1 IRP, until such time as an adequately diverse portfolio of wind exists in its service
2 territory.
3 Definition of Utility Need
4
5 Q. Should utility need be a factor in the price paid for QF power?
6 A. Yes. There is a vast difference in the costs avoided by the QF resource
7 depending on whether the utility is filling a resource deficit with QF power, or the utility
8 already has resources adequate to meet its load obligations. When deficit, avoided costs
9 are those that would be paid for a least-cost alternative resource or resources providing
10 equivalent value. When the utility is in a surplus position, it will not avoid any costs as a
11 result of the QF purchase; at most, the actual value of the QF purchase to the utility is
12 only the avoided fuel costs at existing facilities. A more generous interpretation of the
13 PURPA obligation is to compensate a QF developer during times of system surplus at the
14 market price received for the sale of the energy net of delivery costs to a market trading
15 hub."
16 Q. In Order 29124 the Commission eliminated from consideration utility
17 need in the calculation of published avoided cost rates, relying substantially on the
18 concerns expressed by Staff. What has changed to support your position that the
19 Commission should reverse course?
20 A. In Order 29124, the Commission expressed nine reasons in support of
21 removing the first deficit year. The concerns in 2002 should not exist today.
- ' For example, the short-term PURPA rate is 85% of the market index price, with the reduction intended to
. compensate the utility for delivery of the surplus to the market.
Case No. GNR-E-1 1-03 63 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 10 of 35
1 Q. What was the first reason, and what has changed to again support
2 considering first year deficits?
3 A. The first concern was the lack of regular filings before the Commission
4 that outline utility deficit years. Since 2002 much has changed. Utilities now file
5 biennial IRPs outlining future deficit year explicitly. Each IRP is developed with
6 participation from Commission staffs and other interested stakeholders.
7 To determine Avista's future needs, one needs to look no further than the third
8 paragraph of our August 2011 IRP filing. The document states our needs very clearly:
9 "absent new resource additions or new conservation measures, annual energy deficits
10 begin in 2020.. .the Company will be short 98 MW of summer capacity in 2019.. .winter
11 capacity deficits begin at 42 MW in 2020." Language similar to this has been included in
12 all recent Avista IRPs as far back as 2003. The fact that utilities are clearly defining their
13 resource needs in regularly-filed IRP' s should eliminate this concern.
14 Q. What was the second reason, and has it been resolved?
15 A. The Commission was concerned with the lack of clarity of what exactly
16 the deficit year represented, and whether the determination should be based on an energy
17 or capacity need. As expressed in my previous answer, Avista now tracks both energy
18 and capacity deficiency positions. My proposal, to be fleshed out later in testimony, is to
19 pay for each of these components separately based on separate utility needs for each.
20 With this resolved, the 2002 concern should be fully resolved.
21 III
22 I/I
Case No. GNR-E-11-03 64 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 11 of 35
~ 0
1 Q. What was the third reason, and why should it no longer concern the
2 Commission?
3 A. The third concern was that key planning assumptions greatly affect the
4 result, and that assumptions can vary by utility. While it still is true that planning
5 assumptions differ between the utilities and affect the ultimate deficit year or years,
6 utility IRP processes are subject to significant oversight, both by Idaho Commission Staff
7 and other utility commission staff, and interested parties—including utility customers and
8 potential QF developers. Each utility certainly is different and, therefore, each utility
9 needs to have different assumptions. As such, the balancing of loads and resources that
10 each utility undertakes is for reasons much greater than PURPA, including system
11 reliability, least cost, and meeting environmental and oither social policies.
12 The bottom line is that, with regularly-updated IRPs benefitting from public and
13 Commission oversight, there is a consistent basis for determining load and resource
14 balance such as developed in the utility's IRP.
15 Q. The fourth concern was that utilities prepare their own load forecasts
16 with little oversight, and that they can be manipulated. Has this changed?
17 A. I am not aware of any load forecast concerns over the five past IRPs (2003-
18 present) planning cycles that I have led. But, as explained in my answer to the third
19 concern, regular IRP timelines should eliminate this concern too. The utility load
20 forecast is presented to Staff and other participants in the Company's public IRP process;
21 questions about the forecast can be aired and addressed in that public process.
.
22 III
23 III
Case No. GNR-E-1 1-03
January 31, 2012
65 Kalich, C. (Direct)
Avista Corporation
Page 12 of 35
1 Q. What was the fifth concern, and why should it no longer be of concern?
2 A. The Commission was concerned there was not adequate consistency
3 regarding how long-term market purchases were considered in utility planning. This
4 concern has been addressed. I believe there is general consensus now that any contract,
5 including one for PURPA power, that obligates a seller to sell and a utility to buy power
6 should be included in the load and resources tabulation.
7 Q. Staff also reasoned in 2002 that the difference between PURPA rates
8 during surplus and deficit periods were not great and that the importance of the
9 deficit year had diminished. Does this reasoning hold today?
10 A. No. With a more accurate payment for QF power through the bifurcation of
11 energy and capacity payments as proposed in this testimony, there is a significant
12 difference between payments in deficit and surplus periods. As I explained above, the
13 needs of the utility are essential to successfully honor avoided cost principles, especially
14 in light of the significant additions of variable generation resources to utility systems
15 since 2002. And, as I will show later in my testimony, it is imperative that the
16 Commission recognize the deficit years for energy and capacity to ensure appropriate
17 avoided cost payments are made.
18 Q. What was the seventh concern? Is it still valid?
19 A. The seventh concern was that utilities tend to be surplus in the near term,
20 and that avoided cost rates should not provide incentives for a utility to increase its length
21 to avoid having to purchase PURPA power. It is often true that utilities are surplus in
22 early years; being so is an essential part of providing reliabile utility service. It also is
23 true that QF developers would be affected by these surpluses were they to receive lower
Case No. GNR-E-1 1-03 66 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 13 of 35
1 early-year payments during surplus years. But this effect is a reflection of true avoided
2 costs. It is not reasonable to hold a utility system short both of capacity and reliability
3 simply to promote QF development. So in the early years of a long-term contract, QF
4 developers might receive a lower payment reflective only of the energy value of their
5 projects. But out beyond this time the payment will increase with the utility's need for
6 the QF resource. QF developers also have the opportunity to contract with the utility and
7 postpone their development and deliveries until such time as a deficiency occurs.
8 Q. Does reasoning in 2002, that PURPA project development does not have
9 a large impact on utilities' load and resource balance, hold today?
10 A. No. As recent history shows, PURPA development can start and stop very
11 quickly. The result can be many contracts and hundreds of megawatts of new, and often
OW 12 unneeded, supplies. These figures are not small, especially for a utility like Avista that is
13 growing at fewer than 30 MW per year.
14 Q. Do you have any comments with regard to the last reason that
15 supported the 2002 decision to eliminate the consideration of the utility deficit year?
16 A. Yes. Staff's position in 2002 was that volatile energy prices of that period,
17 and the SAR's linkage to them during periods of utility surplus, posed difficulty when
18 estimating PURPA payments during surplus years. Today we have better options to
19 avoid this volatility and provide the QF developer with a more stable price in surplus
20 years. As explained later in my testimony, I believe that it is possible to provide a fixed
21 payment during surplus years that does not fluctuate over the contract term, and is tied to
22 the actual expected operating costs of the SAR.
Case No. GNR-E-1 1-03 67 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 14 of 35
1 Q. In re-establishing the deficit year, how should utility needs be
2 defined?
3 A. Utility needs should be defined using a publicly-available information
4 source—the biennial utility IRP. The IRP defines the future needs for both energy and
5 capacity on the utility's system, and, as noted before, is developed with participation
6 from Commission staffs and other stakeholders. Each plan defines the timeframe of
7 future deficits.
8 Q. Should load changes since the IRP be considered in the tabulation of
9 utility need?
10 A. Yes. Limited updates should be considered, including changes resulting
11 from a new load forecast, and new contract obligations (e.g., new PURPA contracts) and
12 deliveries incurred since the publication of the IRP. If there is a concern over, for
13 example, the load forecast, the Commission could be consulted to assist the parties in
14 resolving their differences. Alternatively, and at their option, utilities could file annual
15 IRP resource balance updates with the Commission.
16 Q. What happens if a utility is deficit in one of the two PURPA
17 components (energy or capacity), and not in the other?
18 A. As I explain in more detail in other portions of my testimony, QF
19 developers should only receive payments for capacity when the utility has a capacity
20 need. Compensation for energy should be based on a separate tabulation of energy needs.
21 If the utility is in a deficit energy position, the payment should be determined
22 independently of the capacity need and based on the value of that energy to the utility. If
Case No. GNR-E-1 1-03 68 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 15 of 35

1 the utility is surplus energy, the energy payment should be reduced by the costs of

2 delivering the surplus power to the market (i.e., transmission and associated losses).
3 PURPA Rates During Periods of Utility Deficit and Surplus

4 Q. How does the concept of utility need apply to PURPA?

5 A. The principle concept to utilities buying QF power is paying no more than
6 avoided cost. In other words, what least-cost resource and/or acquisition would be
7 avoided with the delivery of QF power under PURPA? Where no costs are avoided by
8 the utility with the addition of a QF, the QF does not reduce the utility's system costs. In
9 the most basic interpretation, the utility would pay nothing for QF power where no costs
10 were avoided; however, another policy position could be that where a market exists for

11 selling surplus energy from the QF, the QF is paid the market value for its energy. 12 No
12 similar active market exists for capacity and no significant value can be obtained through
13 remarketing capacity surpluses created by QF purchases. Because of this, QF developers
14 should receive payments for capacity only when the utility is deficit.
15 Bifurcation of the PURPA Rate

16 Q. Do rates presently paid to QF developers accurately reflect actual
17 avoided costs?

18 A. It depends. Avoided cost rates calculated using the IRP methodology for
19 QFs above the eligibility cap for published avoided cost rates (i.e., 100 kW for wind and
20 solar QFs, and 10 aMW for all other QFs) reflect actual avoided costs because the
12 While historically utilities doing business in Idaho have paid for QF power even when they are in a
surplus position because there has been a market for such energy, there may be structural changes in the
region, such as higher levels of wind, increased transmission constraints, and increased prevalence of
negative prices, that may at some point require a re-evaluation of that position.
Case No. GNR-E-1 1-03 69 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 16 of 35
1 specific values of the resource are considered uniquely. However, the prices paid to
2 QF's under published avoided cost rates can exceed actual avoided costs.
3 Q. Please explain why prices paid to QFs under published avoided cost
4 rates can exceed actual avoided costs.
5 A. The Commission sets rates that utilities must pay all QF developers below
6 an eligibility cap based on a Surrogate Avoided Resource (SAR). The SAR used to set
7 the published avoided cost rates is a gas-fired combined-cycle combustion turbine
8 (CCCT). Today all QF resources below the cap are compensated at a single rate
9 assuming equivalency to the SAR—i.e., the delivery of both energy and capacity—even if
10 the QF resource is variable and/or provides little or no capacity. 13 As a result, the
11 published rates for variable resources can significantly exceed actual avoided costs. This
12 result is not equitable to customers in the case of variable energy QFs like wind, as
13 payments are inclusive of energy and capacity, yet the costs of new capacity investment
14 are not being avoided.
15 Q. What are the consequences of a published avoided cost rate exceeding
16 actual avoided cost?
17 A. The recent experience of some utilities in Idaho shows a "boom" in QF
18 wind development can be a significant consequence that likely would not have been
19 possible absent the structure of published avoided cost rates in Idaho that provided a
20 published avoided cost rate that exceeded the actual avoided costs of wind QFs. That is,
13 Some differentiation exists based on time of day, seasonality, and integration charges. Wind resources
are subject to a wind integration charge that reduces the QF payment by approximately 10%; however, this
reduction is for the consumption of capacity due to wind integration, not a discount for the fact that the
resource does not provide on-peak capacity. Wind "consumes" capacity because existing non-wind
. capacity resources must be dedicated to following and integrating the variable wind generation.
Case No. GNR-E-1 1-03 70 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 17 of 35
1 inflated PURPA prices incented QF developers to construct more wind QFs and sell the
2 output in Idaho. The result is that utility customers bear inflated costs.
3 ifi. THE COMMISSION SHOULD LIMIT VARIABLE GENERATOR
4 PUBLISHED RATE ELIGIBILITY TO 100 KW
5
6 Q. Should the Commission continue to limit variable generation resource
7 (ie., wind and solar) access to published rates to 100 kW?
8 A. Yes. The ability of variable generation resources to break into smaller
9 projects solely for the purpose of qualifying for published rates is well documented and
10 should not be allowed. The best means to prevent this is to keep the 100 kW cap for
11 variable generation resources. Further, the Commission's 100 kW limit for variable
12 generator published rate eligibility is a reasonable limitation and is consistent with federal
S 13 law. I support the continuation of this limit indefinitely. Large variable QF resource
14 additions should be considered on a case-by-case basis to ensure that the prices paid for
15 the QF output reflect the actual avoided cost associated with the particular QF resource.
16 IV. CUSTOMERS ARE BEST PROTECTED THROUGH BIFURCATION OF
17 PURPA RATES INTO SEPARATE ENERGY AND CAPACITY
18 COMPONENTS
19
20 Q. Should the Commission continue to offer a single combined rate for
21 capacity and energy?
22 A. No. The avoided costs of various QF technologies can be vastly different.
23 Some technologies, such as landfill gas, act very much like the SAR, providing both
24 significant contributions in meeting on-peak demand (i.e., capacity), as well as energy.
25 Other resources, such as wind, provide little or no capacity and, therefore, the purchase of
26 the output from such resources under a PURPA contract will not avoid significant
27 capacity investments in alternative resources. Payments to such resources providing little
Case No. GNR-E-1 1-03 71 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 18of35
0 1 or no capacity should be lower than a SAR-equivalent resource. But resources providing
2 on-peak capacity similar to the SAR, but generating less energy on an annual basis than
3 the SAR, such as drop canal hydro projects located in a summer-peaking system, have the
4 potential for much higher per-MWh rates under bifurcation.
5 Q. Please explain why QF developers should be paid separately for
6 capacity and energy.
7 A. Under FERC regulations, a utility obligation exists to purchase energy and
8 capacity from a QF at a price reflective of the value of a QF resource. 14 Further, FERC
9 allows that rates "may differentiate among qualifying facilities using various technologies
10 on the basis of the[ir] supply characteristics.15 One of the largest differences among QF
11 facilities is their ability to provide varying levels of energy and capacity.
12 Q. How do you propose that the Commission ensure that actual avoided
13 costs are not exceeded?
14 A. The Commission's adoption of a lower eligibility cap (100 kW) for wind
15 and solar resources is a significant first step in mitigating the problems associated with
16 paying published avoided cost rates to variable resources because: (i) it is now more
17 difficult for wind and solar QF developers to disaggregate large projects to take
18 advantage of published avoided cost rates, and (ii) the avoided cost rate for most wind
19 and solar projects will be calculated using the IRP methodology, which more accurately
20 reflects the actual avoided costs. 16 The Commission should retain this limitation. The
21 Commission also should bifurcate avoided cost rates into the separate components of
14 18CFR292.303
15 18 CFR § 292.304(a)(3)
16 The IRP Methodology allows the use of updated pricing assumptions (e.g., current natural gas prices,
utility need for the resource).
Case No. GNR-E-1 1-03 72 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 19 of 35
.
0
U
1 energy and capacity. In this way, those resources not reducing utility system
2 requirements (i.e., capacity) or bringing value similar to a utility option are not
3 compensated beyond their actual value.
4 Q. Do you have a recommended method to separate the values of
5 capacity and energy for published rates?
6 A. Yes. And the basic principles apply to both the SAR and IRP
7 Methodologies. The Commission is charged with establishing appropriate avoided cost
8 rates for QF facilities as it relates to capacity and energy. While there might be other
9 methods available to the Commission, for published rates the simplest would be to
10 change slightly the structure of payments.
11 The following table provides an overview of my recommended method for
12 establishing published avoided cost rates.
13 Table 2— Recommended Published Rate Bifurcation Method
14
Rate Method Summary Units
Capacity CCCT SAR for 'Fueled' projects $/MWh
Energy CCCT SAR for "Non-Fueled' projects less CCCI SAR for "Fueled' projects I $/MWh
Q. Please explain your reasoning for creating a new published capacity
17 rate.
18 A. Each published rate-eligible QF developer enabling the utility to avoid
19 capacity investments, irrespective of its fuel source, receives a payment based on the
20 "Fueled" rate and its on-peak capacity contribution. The present Fueled rate
21 approximates the fixed costs of owning and operating the SAR, and approximates the
Case No. GNR-E-1 1-03 73 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 20 of 35
15
lull
1 cost of capacity. 17 No new base calculations are required to determine the capacity
2 payment because the Commission already calculates a Fueled rate.
3 Q. How would your proposed method account for two resources with
4 similar on-peak capacity contributions, but different generation characteristics?
5 A. It is not fair to pay one resource with a low capacity factor and an
6 equivalently high on-peak contribution the same per-MWh payment as second base load
7 plant operating with a relatively high capacity factor all year round. Using the method,
8 the low capacity factor resource would receive much lower total compensation even
9 though the resource provided the same on-peak capacity benefit to the utility. To ensure
10 a similar payment is made for a similar on-peak capacity contribution, the first step is to
11 covert the SAR per-MWh payment level to a total annual capacity payment. This is
12 accomplished by multiplying the per-MWh rate of the Fueled schedule by the assumed
13 net capacity factor of the SAR resource. This value is then divided by the expected
14 annual capacity factor of the specific QF resource to arrive at a per-MWh rate. The
15 following table illustrates this concept where you have differing resources providing
16 different on-peak capacity contributions. Consistent with my proposal, I used the
17 level ized fueled rate as a proxy for capacity value.
18 III
19 III
20 III
21 III
22 III
17 It does not include fuel and variable operating costs, those generally associated with energy production.
Case No. GNR-E-1 1-03 74 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 21 of 35
0 1 Table 3— Comparison of OF Project Capacity Payments
Line Item SAR Geo Hydra Solar Wind Nate
1 Resource Size (MW) 1 1 1 1 1 assumption
2 Capacity Contribution (%) 100 100 100 35 5 assumption
3
SAR 20-Year Lev. Fueled
Rate (2013 First Year
Delivery, $/MWh) 25.51
from present Avista
PURPA rate
schedule
4 1 Net Capacity Factor 92.0% 1 85.0% 34.0% 22.6% 1 33.0% assumption
5 Annual Generation (MWh) 8,059 7,446 2,978 1,980 2,891
line I * line 4*8760
hours
6
Annual Capacity Payment
($000s) 206 206 206 72 10
SAR line 6 * line 2/
SAR line 2
7 Capacity Payment ($/MWh) 25.51 27.61 69.03 36.35 3.56 line 6 I line 5
4
5 The table shows that payments can greatly exceed or fall below the SAR rate
6 based on the capacity contribution and expected, or average, output of the resource. The
7 hydro example shows how this low capacity factor resource receives a per-MWh capacity
Ll
8 payment much higher than the SAR resource. The table also shows how a solar resource,
9 even though it has a much lower on-peak capacity contribution can still receive a per-
10 MWh payment exceeding the SAR resource with a 100% on-peak contribution. 18 The
11 table shows that the payment for wind is much lower than the SAR, primarily because of
12 its low on-peak contribution.
13 Q. What do you mean by "on-peak contribution"?
14 A. For customers to derive a capacity benefit (i.e., for the utility to avoid
15 capacity investment costs) from the PURPA project, the QF must be capable of reliably
16 generating during peak load hours of the year. If the QF cannot be relied on to generate
17 during the utility's peak load hours of the year, the utility will have to build or otherwise
18 procure a resource that the utility can rely on to generate during those peak load hours
19 and, therefore, the QF does not avoid any capacity investment costs. This means the QF
20 must be capable of reliably providing output during peak hours in the winter months for
The price assumes the solar resource is located in a summer-peaking utility location. Where located in a
. winter-peaking utility's territory, like Avista, the payment likely will be much smaller.
Case No. GNR-E-1 1-03 75 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 22 of 35
1 Avista, and likely during the summer months for both Idaho Power and PacifiCorp.'9
2 Eligibility for capacity payments must be tied to the expected on-peak contribution of the
3 QF resource.
4 Q. Do you have any other recommendations with regard to published
5 rate capacity payments?
6 A. Yes. With my proposal I recommend changing the rate for capacity in the
7 published tables to a per-MW price instead of a per-MWh price, and then footnote that
8 the payment made to the QF developer will be dependent on the capacity factor and on-
9 peak capacity contribution of the resource. It might also be useful to provide one or more
10 example calculations to show how the capacity payment is "translated" to a per-MWh
11 charge. To make things less confusing, the "Fueled" rate schedule should be re-named as
12 the "Capacity" rate schedule.
13 Q. Table 3 explains that the per-MWh capacity payment rises as the
14 capacity factor of the resource falls. What is to prevent a QF developer from under-
15 estimating the QF's capacity factor to obtain higher total compensation for its
16 capacity contribution?
17 A. After the annual SAR-based capacity payment is calculated, it should
18 serve as a cap on total payments in any given year to remove any incentive for a QF to
19 under estimate output.20 If the QF developer is shown over time, say over two or five
20 years, to have substantially under-estimated the QF' s capacity factor, I believe that the
21 capacity rate should be adjusted downward accordingly.
19 Idaho Power and PacifiCorp are "summer-peaking" utilities, as documented in their biennial integrated
resource plans.
. 20 Adjusted based on the specific capacity factor of the QF resource.
Case No. GNR-E-1 1-03 76 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 23 of 35
1 Q. Please explain your reasoning for a new published energy rate.
2 A. Under my proposal, QF projects eligible for the Fueled rate would receive
3 payments for their energy as they do today—based on a gas index. But "Non-Fueled"
4 projects like wind and biomass would receive payments based on the variable operating,
5 variable maintenance and fuel costs associated with the SAR. This value is arrived at by
6 reducing the Non-Fueled SAR rates by the Fueled (Capacity) rates.
7 Q. Do you have any other recommendations with regard to published
8 rate energy payments?
9 A. Yes. To again make things less confusing, I would name this modified
10 "Non-Fueled" rate schedule (i.e., the Non-Fueled rate schedule less the Fueled rate
11 schedule) as the "Energy" rate schedule.
12 Q. How would the changes you propose affect the major QF
13 technologies?
14 A. The major change is that QF resources eligible for published avoided cost
15 rates, to the extent they provide significantly less capacity than the SAR, receive a lower
16 rate more commensurate with the costs they enable the utility to avoid. For example, if a
17 wind resource provides a five percent peak capacity value to the utility, it would witness
18 a reduction in the capacity component of the avoided cost rate that would be reflected in
19 its PURPA compensation. Biomass resources likely would be affected only modestly, if
20 at all, because they tend to provide system capacity all year round. Solar would fall
21 somewhere in the middle based on its expected contribution to utility system peak.
22 Hydro resources would benefit greatly relative to the existing structure. See the
23 following table, a continuation of Table 3.
Case No. GNR-E-1 1-03 77 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 24 of 35
.
0
.
Table 4— Comparison of OF Project Total Payments
Line Item SAR Geo Hydro Solar Wind Note
1 Resource Size (MW) 1 1 1 1 1 assumption
2 Capacity Contribution (%) 100 100 100 35 5 assumption
SAR 20-Year Lev. Fueled from present Avista
Rate (2013 First Year PURPA rate
3 Delivery, $/MWh) 25.51 schedule
4 Net Capacity Factor 92.0% 85.0% 34.0% 22.6% 33.0% 1 assumption
line 1 * line 4 * 8,760
5 Annual Generation (MWh) 8,059 7,446 2,978 1,980 2,891 hours
Annual Capacity Payment SAR line 6 * line 2/
6 ($000s) 206 206 206 72 10 SAR line 2
Capacity Payment
7 ($/MWh) 25.51 27.61 69.03 1 36.35 3.56 line 6/line 5
SAR line 10— SAR
8 Energy Payment ($/MWh) 45.45 line 7
9 Integration ($/MWh) 0 0 0 (6.50) (6.50)
SAR from schedules
Total (combined) PURPA other resources,
10 Rate ($/MWh) 1 70.96 1 73.06 1 114.48 75.30 1 42.51 lines 7 + 8 + 9
As shown, PURPA rates (line 10) can vary significantly depending on the
5 resource type under this proposal. It is also important to point out that these prices
6 assume the utility has both capacity and energy needs throughout the delivery period.21
7 The annual capacity payment (line 6) for geothermal is the same as the SAR because the
8 expected output is the same, even though the per-MWh rate differs due to a difference in
9 expected annual MWh output. Solar obtains a capacity payment premium relative to the
10 SAR because its capacity contribution relative to its capacity factor is higher than the
11 SAR ratio .22 Wind receives a much lower overall payment because only a small on-peak
12 capacity contribution is attributed to the resource. The largest winner using this method
13 is the canal drop hydro facility because it, in this example, provides capacity and operates
14 at a low capacity factor relative to the SAR. So to compensate it for avoided capacity
21 Drop canal hydro facilities would not receive a capacity payment in winter-peaking systems, since the
resource does not generate during the winter. The on-peak capacity payment likely would differ for solar
in a winter-peaking system because the resource generates significantly less during winter on-peak hours
relative to on-peak summer hours. There also would be discounts in periods where the purchasing utility is
surplus energy to account for costs necessary to deliver the surplus energy to a market trading hub.
22 Again, this assumes that the solar resource is located in a summer-peaking utility territory where on-peak
contributions are higher than in a winter-peaking system.
Case No. GNR-E-1 1-03 78 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 25 of 35
1
2
'I
ru
.

1 costs, its rate per MWh must rise. Please note that I have simplified the energy payment
2 line (line 8) for hydro, solar and wind in this example. These resources will receive a
3 modified payment depending on their specific energy shape over the year. For example,
4 a solar plant likely would obtain a slightly larger energy payment because its generation
5 is correlated with peak load periods. Wind might get a slightly lower energy payment
6 given that wind tends to have a slight bias toward off-peak hours.
7 Q. How will the bifurcation affect resources obtaining their pricing
8 through the IRP Method?
9 A. The IRP Method will conceptually follow the structure described above.
10 The utility purchasing from a QF will pay the QF for energy based on the energy costs
11 avoided by the utility. The utility also will pay only for capacity based on the capacity
12 costs that are avoided due to the QF.
13 V. QF DEVELOPERS SHOULD RECEIVE PAYMENTS FOR CAPACITY
14 ONLY WHEN THE UTILTY IS DEFICIT
15
16 Q. What should QF developers be paid when the utility is deficit?
17 A. When the utility is deficient, the QF developer should be compensated
18 based on the costs the utility and its customers avoid by not having to invest in alternative
19 power sources. This value is best identified by a recent competitive acquisition process
20 or the utility's latest IRP, both adjusted for any significant changes that have occurred
21 since the time of the acquisition or publication of the IRP.23 This methodology is best
22 applied under the "IRP Methodology." Under published rates, the values during periods
23 Such changes can include load changes, new committed resources and contracts, fuel prices, and major
is changes to the wholesale marketplace (e.g., major additions or reductions to the regional resource stack).
Case No. GNR-E-1 1-03 79 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 26 of 35
0 1 of deficit are based not on the IRP or recent acquisitions, but instead on a surrogate
2 avoided cost resource.
3 Q. What should QF developers be paid when the utility is surplus
4 capacity?
5 A. The utility does not avoid any capacity costs by purchasing output from a
6 QF during those times when the utility does not have a need for capacity. Because there
7 is no need, and because no active capacity market exists in the northwest, the capacity
8 value of QF power during surplus periods should be zero.
9 VI. QF DEVELOPERS SHOULD RECEIVE LOWER ENERGY PAYMENTS
10 DURING UTILITY SURPLUS PERIODS TO REFLECT THE COSTS OF
11 TRANSMITTING SURPLUS POWER TO MARKET
12
13 Q. Should QF developers be compensated for energy when the utility
14 Integrated Resource Plan (IRP) shows a surplus?
15 A. I am not greatly concerned about providing a payment for energy when the
16 IRP shows a utility energy surplus and no energy costs are actually avoided because a
17 fairly liquid market for energy at the Mid-Columbia trading hub exists. As footnoted
18 above, there may be a need to revisit this policy in the future due to changes in
19 circumstances. However, if utilities are required to pay for unneeded energy, the avoided
20 cost during the surplus period should reflect only the net value of QF surplus sold into the
21 short-term wholesale marketplace.
22 Q. What is the net value of QF energy when the utility is surplus ana
23 does not avoid any costs by its purchase?
24 A. The value should reflect the market. For Avista in the northwest the
25 principle market is at the Mid-Columbia trading hub. The energy rate should not exceed
Case No. GNR-E-1 1-03 80 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 27 of 35
0 1 the Mid-Columbia price net of those costs incurred to deliver the surplus power to that
2 point of delivery.
3 Delivery to the Mid-Columbia (i.e., through the use of transmission) is limited by
4 physical constraints. Avista has limited transfer capability, and surplus QF power sold at
5 the Mid-Columbia displaces other utility opportunities to sell existing surpluses of power
6 or to generate revenues from the resale of unused transmission to third parties.
7 Therefore, the price paid for QF power during surplus periods should be reduced by
8 Avista's transmission costs, which currently includes a $2.72 per kilowatt rate under
9 Avista's Open Access Transmission Tariff, and a defined three-percent energy loss

10 factor.
11 Q. What is the total transmission discount when applied to base load,
12 wind, solar, biomass and drop canal hydroelectricity plants?

13 A. Because transmission costs are not volumetric (i.e., based on the energy
14 generated), but instead on the level of reserved transmission capacity, the discount for
15 transmission costs varies depending on the capacity factor of the PURPA facility. The
16 following table estimates the discount for transmission costs based on an assumed
17 capacity factor for various QF technology types.

18 III

19 I/I

20 III

21 III

22 III
Case No. GNR-E-1 1-03 81 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 28 of 35
•1 Table 5- Transmission Costs of Surplus QF Electricity (for a 1.0 MW Project)24
El
.
Line Item Base
Load/
Biomass
Drop.
Canal
Hydro
Wind Solar Note
1 QF Net Capacity Factor 92.0% 34.0% 33.0% 20.0% Assumption
2 QF Average Energy (MWh/mo.) 672 248 241 146 Line 1 * 730 hrs in avg mo.
3 Transmission ($&W-month) 2.72 2.72 2.72 2.72 Avista OATT
4 Transmission ($/MWh) 2.96 8.00 8.24 13.60 line 3 / line 1
5 Energy Rate ($IMWh) 45.45 45.45 45.45 45.45 Table 4, line 8
6 Losses 3.0% 3.0% 3.0% 3.0% Avista OA1T
7 Losses ($/MWh)(1] 1.36 1.36 1.36 1.36 line 5 * line 6
8 Total Re-Marketing Costs 4.32 9.36 9.61 14.96 line 4 + line 7
9 As % of Energy Rate 9.5% 20.6% 21.1% 32.9% line 8 / line 5
PA
3 The table explains that the average cost of delivering surplus energy is dependent
4 on the capacity factor of the QF resource. Drop canal hydro and wind have a discount
5 that is approximately twice that of resources operating in more base-load configurations.
6 Their discount is similar because their capacity factor is similar. Solar, due to its even
7 lower capacity factor, has a cost approximately three times that of base load generation.
8 Q. Should the net energy rate during surplus periods be reduced by the
9 full transmission rate? In other words, is it possible that the utility will have surplus
10 transmission from its marketing operations that could be used to transmit surplus
11 QF power to market without cost?
12 A. Yes, the rate should be reduced by the transmission rate. It is possible that
13 the merchant side of Avista' s business might have surplus transmission capacity rights
14 from time to time. However, this transmission has value to customers as it can be resold
15 by Avista's transmission group to third parties. Reserving transmission for the purpose
16 of moving QF power to market would reduce those transmission revenues. Further,
17 losses associated with transmitting power to the Mid-Columbia hub exist, irrespective of
18 the assumed cost of the transmission reservation.
24 Values shown are for a 1 MW facility.
Case No. GNR-E- 11-03 82 Kalich, C. (Direct)
January 31, 2012 . Avista Corporation
Page 29 of 35
0 1 Q. Do you have any other observations that supporting your position
2 that surplus QF energy be discounted for the full cost of transmission?
3 A. Yes. In 2006, FERC issued Order No. 688, reiterating its 1995 finding
4 "that determinations of the avoided-cost rate must take into account all alternative
5 sources including third-party suppliers and an electric utility does not pay for electric
6 energy it does not need. ,25 Accordingly, the Commission could decide that QF
7 developers should receive no payments when the utility is surplus.
8 Additionally, current short-term PURPA rates recognize the impacts of market
9 delivery costs. Any PURPA power purchased this way receives a payment equal to 85%
10 of the Mid-Columbia index price. The reduction is an attempt to cover costs associated
11 with delivering surplus energy to the market. It is therefore reasonable to protect
46 1
12 customers against transmission costs when accepting surplus energy.
13 VII. PURPA CONTRACTS SHOULD NOT BE EXECUTED EARLIER THAN
14 FIVE YEARS BEFORE COMMERCIAL OPERATION; RATES SHOULD NOT
15 BE SET MORE THAN TWO YEARS PRIOR
16
17 Q. Should the ability of the QF developer to sign a PURPA contract
18 ahead of scheduled commercial operation be limited?
19 A. Yes. The utility should not be expected to enter into a contract more than
20 five years ahead of expected deliveries. I would prefer to limit contracting to two years;
21 however, offering PURPA contracts with deliveries too few years into the future would
22 limit developer opportunities to receive a capacity payment in the early years of the
25 PURPA Section 210(m) Regulations Applicable to Small Power Production and Cogeneration New
Facilities, 117 FERC ¶ 61,078 (2006) ("Order No. 688") (emphasis added); see also Southern California
Edison Company and San Diego Gas & Electric Company, 70 FERC 161,215 at 61,677-78,
• reconsideration denied, 71 FERC ¶ 61,269 at 62,078 (1995).
Case No. GNR-E-1 1-03 83 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 30 of 35
0 1 contract. By committing itself to deliveries further into the future, the QF developer will
2 be more likely to receive compensation for both energy and capacity.
3 Q. Should the prices be set in a contract with delivery occurring as far as
4 five years into the future?
5 A. No. I recommend that prices be locked in no sooner than two years ahead
6 of commercial operation. Too many things affecting price can change over a five-year
7 term, both for the QF developer and the utility. This said, it would not be unreasonable
8 for the utility to provide estimates over time of the then-current PURPA rates so that the
9 QF developer would be apprised of the value of its future output.
10 VIII. PURPA CONTRACTS MUST HAVE MEANINGFUL LIQUIDATED
11 DAMAGE AND TERMINATION PROVISIONS
12
13 Q. Do you support the continued inclusion of liquidated damages provisions in
14 PURPA contracts?
15 A. Yes. Liquidated damages provisions, including adequate security to
16 ensure payment of liquidated damages if necessary, are one of two key protections a
17 utility must have with any developer who might otherwise not exercise their "put option"
18 in the absence of an obligation on the part of the QF to perform. Once a PURPA contract
19 is executed by the parties it becomes a firm contract in the utility's resource stack and, as
20 such, the proposed QF resource postpones the development of other resource alternatives;
21 in other words, the contract then allows and obligates the Company to avoid the costs
22 associated with investing in its system to ensure reliable electricity service. To the extent
23 the PURPA developer does not honor its contract commitments the utility ends up at the
24 last moment having to procure other resources, potentially at higher cost. In the absence
25 of meaningful liquidated damages, the QF developer has a free option to either honor its
Case No. GNR-E-1 1-03 84 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 31 of 35
1 contractual commitment where the avoided cost rate under the contract (agreed to years
2 before commercial operation) is greater than its alternatives at the time of commercial

3 operation, break its commitment and sell to a 31 party if it can secure a higher price, or
4 simply cease development where market conditions have changed.

5 Q. At what level should the Commission set the delay liquidated damages
6 deposit?

7 A. There is precedent in recent Idaho PURPA contracts for a $45 per kilowatt

8 deposit based on installed capacity. This deposit provides recourse to the utility where
9 the QF developer does not build its resource as contractually agreed. I recommend that
10 this level be the minimum required in all PURPA contracts.

11 Q. You stated that liquidated damages provisions are one of two key
12 protections that utilities need to protect against developers using PURPA as a
13 speculative put option. What is the second key protection?

14 A. The second key protection is meaningful termination rights if the QF fails
15 to achieve commercial operation within the timeframes established in the PIJRPA

16 contract.

17 Q. What are the termination provisions you envision as part of a PURPA
18 contract?

19 A. Liquidated damage provisions by themselves work well in a market where
20 prices are rising. The QF developer has an incentive to bring its project online because if
21 it does not, damages will be based on the difference between the higher market price of
22 replacement power and the lower PURPA contract price. This payment is backed by the

23 liquidated damages security.
Case No. GNR-E-1 1-03 85 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 32 of 35
1 In a period of falling prices, however, liquidated damages are not assessed
2 because market prices are lower than the contract price. The developer in this case might
3 decide to postpone construction until prices rise. The utility meanwhile has to decide
4 how to reliably fill the deficit left by a non-performing PURPA contract and is exposed to
5 supply risk and future price increases.
6 To ensure QF developer obligations are honored, each PURPA contract should
7 have a termination clause enabling the utility to terminate 180 days beyond the
8 committed online date in the contract. This simple provision will put all QF developers
9 on notice that their failure to honor PURPA contract obligations will result in contract
10 termination.
11 Q. When should the liquidated damages deposit be required of the QF
12 developer?
13 A. Recent FERC rulings highlight the risk of a PURPA contract constituting
14 a legally enforceable obligation on the utility. This obligation needs to go both ways to
15 ensure both parties honor their commitments. The best way to ensure a level playing
16 field is to require the QF developer to post the liquidated damages deposit at the time that
17 the legally enforceable obligation arises—i.e., when the utility has tendered a contract
18 and the QF developer executes and returns the tendered contract obligating the utility to
19 purchase contract output. Absent this provision, the utility has the potential to be subject
20 to a legally enforceable obligation without recourse.
21 III
22 III
23 III
Case No. GNR-E-1 1-03
January 31, 2012
86 Kalich, C. (Direct)
Avista Corporation
Page 33 of 35
1 IX. SAR GAS PRICES SHOULD BE UPDATED ANNUALLY USING THE
2 ENERGY INFORMATION ADMINISTRATION'S ANNUAL ENERGY
3 OUTLOOK
4
5 Q. Do you have any thoughts related to the present SAR natural gas
6 price update cycle?
7 A. Yes. Natural gas is the single largest component of the SAR price
8 calculation. While parties to various PURPA proceedings before this Commission have
9 struggled to find a fair and timely source for estimating future natural gas prices, they
10 generally agreed that the forecast should be from a public data source. Presently the price
11 is tied to NPCC's work; however, this forecast is not updated with regularity and there is
12 no guarantee that the forecast will be updated between its once-every-five-years Power
13 Plan. Another source should be used.
14 Q. Do you have a recommended source for an annual update of the
15 natural gas prices?
16 Yes. A better alternative is the Energy Information Administration's ("EIA")
17 Annual Energy Outlook report. This federal government source is published annually
18 and would provide a publicly-available forecast unbiased by anyone with vested interest
19 inPURPA.
20 X. THE COMMISSION SHOULD NOT DETERMINE RECS OWNERSHIP
21 IN THIS DOCKET
22
23 Q. Is Avista taking any position on Renewable Energy Credits (RECs) in
24 this proceeding?
25 A. Avista believes this proceeding should be limited to the SAR and IRP
26 Methodologies, and Avista therefore has limited its testimony accordingly.
27 I/I
Case No. GNR-E-1 1-03
January 31, 2012
87 Kalich, C. (Direct)
Avista Corporation
Page 34 of 35
1 Q. Does this conclude your direct-filed testimony?
2 A. Yes.
1 16,
Case No. GNR-E-11-03 88 Kalich, C. (Direct)
January 31, 2012 Avista Corporation
Page 35 of 35
.
~ 0
1 Q. Please state your name, the name of your employer, and your business
2 address.
3 A. My name is Clint Kalich. I am employed by Avista Corporation
4 ("Avista") at 1411 East Mission Avenue, Spokane, Washington.
5 Q. Did you provide direct testimony in this proceeding?
6 A. Yes. I submitted the Testimony of Clint Kalich filed in this proceeding on
7 behalf of Avista Corporation on January 31, 2012.
8 Q. What is the purpose of your rebuttal testimony?
9 A. In my rebuttal testimony I respond to issues raised in direct testimony filed
10 in this case by Rick Sterling and Dr. Cathleen McHugh on behalf of the Idaho Public
11 Utilities Commission ("Commission") Staff, Mr. Schoenbeck on behalf of Northside
12 Canal Company, Twin Falls Canal Company ("TFCNSC"), and Dr. Reading on behalf of
13 Clearwater Paper Corporation, J.R. Simplot Company, and Exergy Development Group
14 of Idaho, LLC.
15
16 Testimony of Commission Staff
17 Q. Please summarize your views on the direct testimony of Commission
18 Staff.
19 A. Commission Staff took a number of positions of interest to Avista,
20 summarized by Table Ri.
21
1
Case No. GNR-E- 11-03
89 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
~ 0
U
.
1 Table Ri - Summary of Avista Responses to Staff Positions
No. Staff Position Avista Position
I Retain SAR for Small QFs Support
2 Limit published rate eligibility to 100 kW Support for wind and solar facilities
Limit published rate eligibility for non- Oppose, in favor of limiting
wind/solar to 10 published rate eligibility for non-
wind/solar to 10 MW nameplate
Replacement of NPCC with EIA Mountain Support natural gas forecast
Discount QF payments for transmission Support costs
6 Base capacity payment on SCCT for IRP Generally Support methodology
7 Consideration of utility energy and/or Support capacity needs in calculating avoided costs
8 Modifications to Avista-edited SAR model Support
9 Annual updates to assumptions Support
10 No prior-to-commercial-operation time Oppose in favor of 5-year limit limit on PURPA contract requests
11 5-year PIJRPA rate lock-in term Support
12 QF contracting procedures & rules Support
13 Resource-specific values for capacity Support payments
14 Adjust avoided cost rates in exchange for oppose assignment of RECs to utility
2
3 Q. In his testimony, Mr. Sterling indicated that the Integrated Resource
4 Planning ("IRP") methodology should not be applied to small projects (i.e., solar
5 and wind facilities up to 100 kW nameplate and up to 10 aMW for all other project
6 types) and the Surrogate Avoided Resource ("SAR") methodology should continue
7 to be used for such small projects. Do you agree that the SAR methodology should
8 be retained for small projects?
9 A. Yes. I agree with Mr. Sterling that the SAR should continue to be used for
10 relatively small projects. That said, I think some minor changes to the SAR methodology
11 are warranted.
12 Q. What revisions should be made to the SAR?
2
Case No. GNR-E- 11-03 90 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
1 A. First, I support Staff's position to maintain the 100 kW nameplate cap for
2 wind and solar published avoided cost rates. Although I do not agree that the eligibility
3 cap for published avoided cost rates for such variable (wind and solar) projects should be
4 changed, I do agree with Mr. Schoenbeck that the eligibility cap should be 10 MW
5 nameplate capacity for all other types of projects (i.e., projects that are not wind or solar
6 projects).
7 Q. Why do you support changing the eligibility cap for published
8 avoided cost rates for projects other than wind and solar from 10 aMW to 10 MW
9 nameplate capacity?
10 A. Because the IRP methodology produces avoided cost rates for projects that
11 more accurately reflect the utility's actual avoided cost, the IRP methodology should be
12 used to calculate avoided cost rates for all but very small projects. Capacity limits
13 generally are stated in terms of nameplate capacity, not average energy. Using the
14 average megawatt (aMW) term is fairly unique to the northwest. More importantly,
15 using aMW has the potential to allow very large QFs to benefit from contracting terms
16 (and arbitrage). For example, prior to the 100 kW limit imposed on solar and wind
17 projects by the Commission, the published avoided cost rates, assuming a 20% capacity
18 factor, could be applied to projects as large as 50 MW.1 Application of published
19 avoided cost rates to such large variable projects led to unintended consequences and, as
20 a result, the Commission reduced the eligibility cap for access to published rates for wind
21 and solar projects to 100 kW.
50 M1v1/ * 20% capacity factor = 10 aMW.
3
Case No. GNR-E-1 1-03 91 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
.

1 Although it might be difficult to disaggregate other types of projects, it is possible
2 that developers will find similar ways to arbitrage published rates to their favor at the
3 expense of utility customers. The potential for such arbitrage is enhanced when
4 published avoided cost rates are available for larger projects. Capping published rate
5 eligibility at 10 megawatts (MW) nameplate would limit the arbitrage opportunities of
6 creative developers without compromising the intent of PURPA.

7 Q. In her testimony, Dr. McHugh recommends adoption of the EIA
8 Mountain region gas forecast. Do you agree with this change?

9 A. Yes. In my direct testimony I recommended use of the EIA Pacific
10 forecast. The Mountain forecast covers Idaho and, therefore, I agree that the EIA' S
11 Mountain forecast should be used.

12 Q. With regard to the SAR and IRP methodologies, Mr. Sterling
13 proposes to account for transaction-related transmission costs and losses. Do you
14 agree that such transmission costs and losses should be accounted for?

15 A. Yes. As outlined in my direct testimony, PURPA rates should be
16 discounted for transaction costs associated with re-selling surplus power into the market.

17 Q. Mr. Sterling recommends adopting a simple-cycle combustion turbine
18 (SCCT) for the calculation of capacity value in the IRP methodology. Do you
19 concur?

20 A. Generally yes. Avista's IRP methodology does not use any single

21 resource to calculate capacity value. It is dependent on the PRISM model, a software
22 package designed to select an optimal future resource portfolio. To determine the value
23 of a new QF resource, it is included in PRISM and the variance in value becomes the
. 4
Case No. GNR-E-11-03 92 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
.

1 avoided cost of capacity. The avoided capacity cost can be a melding of the various
2 resources avoided; it might or might not include a SCCT.
3 In reality no single resource perfectly reflects actual avoided capacity. Avista
4 views its PRiSM capacity value method as superior to picking a single capacity resource
5 in that all resources of the Integrated Resource Plan preferred resource strategy are
6 considered. That said, Avista can algebraically adjust its PRISM results to base the
7 capacity payment on a SCCT if the Commission so orders. Any adjustments from
8 PRiSM capacity results would be balanced by adjusting the energy component of the
9 PURPA rate. Although Avista is not opposed to Staff's proposal, our recommendation
10 would be to use the IRP Methodology; for Avista this means using PRiSM to calculate
11 capacity value.
0 12 Q. Does Avista agree with Dr. McHugh that utility need should be
13 considered when determining avoided costs?
14 A. Yes. Utilities should not pay for capacity when they do not require it.
15 Need should be considered for both published rates based on the SAR method, and for
16 rates calculated using the IRP methodology.
17 Further, Avista supports what it understands to be efforts by Staff to enhance the
18 SAR model to prevent small deficits outside of peak-need months from disqualifying a
19 QF resource from receiving capacity payments. This enhancement will benefit certain
20 drop-canal hydroelectricity projects and could benefit other resources that might perform
21 better (i.e., have higher on-peak contributions) in utility peak need months.
22 Q. Do you agree with model corrections suggested by Staff witness Dr.
23 McHugh to the Avista-edited SAR model?
. 5
Case No. GNR-E-1 1-03 93 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
0 1 A. Yes. Dr. McHugh's recommended corrections to Avista's edited version
2 of the SAR model are appropriate.
3 Q. Do you agree with Mr. Sterling's recommended annual updates under
4 the IRP methodology?
5 A. Generally, yes. Mr. Sterling advocates for updating IRP-methodology
6 assumptions annually for fuel price forecasts, load forecasts, and new contract
7 obligations. Avista agrees that these are the important assumptions to update between
8 IRP filings. To the extent that the Commission orders methodologies obligating utilities
9 to quantify renewable energy credit (REC) values in the avoided cost calculations, I
10 believe that REC prices also should be updated annually.
11 Q. Mr. Sterling testified that he believes "it might be difficult to
12 implement" five year limits on contracting before commercial operation without
13 violating PURIPA. Do you agree?
14 A. No, I do not. My understanding of PURPA is that utilities generally are
15 obligated to purchase QF power, not provide a guarantee infinitely into the future.
16 Avista's proposal to cap contracting to five years before commercial operation is not a
17 limit on QF access to PURPA rates. Instead, limiting contracting to no more than five
18 years prior to commercial operation bounds utility customer risk. Such a limitation is
19 reasonable and it would not remove the utility obligation to purchase QF power; rather, it
20 would prevent speculative projects from languishing in the utility's resource portfolio
21 plan for extended periods of time.
22 Q. Witness Sterling in his testimony questions whether your proposal to
23 obligate utilities to provide locked-in prices for two-years prior to commercial
• 6
Case No. GNR-E- 11-03 94 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
0 1 operation in a new PURPA contract is reasonable. He recommends five years. Do
2 you support his position?
3 A. Yes, but with reservations. Mr. Sterling explains at line 8 on page 34 of
4 his direct testimony that "few projects achieve commercial operation within two years of
5 contract execution, but most achieve it within five years." In recent experience,
6 successful commercial operation even of projects larger than those qualifying under
7 PURPA tend more toward two years, not five. The 105 MW Palouse Wind project, for
8 example, will come online approximately 18 months after the developer executed a
9 contract with Avista; actual construction will occur over a period closer to 12 months.
10 Q. Did any of the other parties in this case object to limiting contracting
11 to two years?
10 12 A. Yes. Dr. Reading, on behalf of Clearwater Paper, J.R. Simplot, and
13 Exergy Development, explained on page 43 of his direct testimony, at line 7 that ". . .it
14 could take much longer than two years to complete construction alone." In an attempt to
15 understand Dr. Reading's statement that it could take much longer than two years to
16 complete construction, Avista submitted a production request to Exergy, requesting a list
17 of PURPA facilities that Exergy developed or participated in the development of during
18 the last five years and a detailed construction timeframe for each such facility.2 In
19 response to Avista' s request, Exergy stated that "Exergy begins construction when land
20 rights are finally secured from the landowner ... therefore the construction process takes
21 several years." Yet Exergy's own press releases do not support Dr. Reading's testimony,
22 or Exergy' s response to Avista' s production request. Rather, Exergy' s own press releases
2 Production Request 4(C) and 4(D) of Avista Corporation's First Production Request to Clearwater Paper
Corporation, J.R. Simplot Company and Exergy Development Group of Idaho (Production Request 4(C)
. and 4(D) were directed solely to Exergy).
7
Case No. GNR-E-11-03 95 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
1 demonstrate that projects can be built in less than two years. The press releases explain
2 that Exergy Development, one of the largest developers of QF power in Idaho over the
3 past few years, built 11 wind farms in Idaho over a period of approximately six months,
4 with construction beginning in late August 2010 and ending by February 2011. The two
5 press releases, and Exergy' s responses to Avista' s Production Request 4(C) and 4(D), are
6 included as Exhibit 101 to my testimony.
7 Q. Are there any other examples supporting your position that locking in
8 prices two years prior to commercial operation is reasonable?
9 A. Yes. Idaho Power's Langley Gulch, a much larger and complex project, will be
10 completed in approximately two years. The project began construction in June 2010 and
11 is now (in June 2012) producing test energy. Idaho Power has scheduled a ribbon cutting
12 ceremony for the plant in June and anticipates commercial operation in July 2012. If a
13 project of this magnitude can be completed in such a timeframe, certainly it is not
14 unreasonable to expect smaller and less complicated PURPA projects to meet a two-year
15 timeline. This said, Avista can support Commission Staff's five-year recommendation.
16 Where a project cannot meet this timeline, the utility should be able to recalculate QF
17 rates at its option.
18 Q. Mr. Sterling supports PacifiCorp's proposal in this case that a tariff
19 be adopted specifying contracting procedures and rules for QF contracts and
20 recommends that each of the utilities be directed to prepare similar tariffs to
21 PacifiCorp's Schedule 38, and that a separate docket be opened for review and
22 comment on the specific details that would be contained in each proposed tariff. Do
.
96 8
Case No. GNR-E-1 1-03 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
10
1 you support the adoption of a tariff specifying contracting procedures and rules for
2 QF contracts?
3 A. Yes. I agree that a tariff similar to PacifiCorp's Schedule 38 could be
4 helpful both to the utilities and project developers, and could limit future complaints
5 before this Commission. If such a proposal is adopted, each utility should be allowed to
6 develop a tariff with terms specific to its needs. Accordingly, I support Mr. Sterling's
7 recommendation that a separate docket be opened in which each utility submits a
8 proposed tariff for review and comment.
9 Q. Commission Staff witness Dr. McHugh recommends "using resource-
10 specific values for determining capacity payments." Do you concur?
11 A. Yes. QF developer compensation should be capped at utility avoided
12 costs. Given that the capacity contributions of resources can differ greatly, it is important
13 to recognize the actual capacity contribution of each resource when calculating PURPA
14 rates, both published and through the IRP methodology.
15 Q. Mr. Sterling recommends that the Commission deem the
16 environmental attributes (RECs) associated with QF resources as owned by the
17 purchasing utility, but that the avoided cost rate calculation should be adjusted to
18 reflect this assignment. Do you agree with his position?
19 A. No. Avista did not take a position on REC ownership in its direct
20 testimony in this proceeding. However, to the extent the Commission chooses to assign
21 RECs to utilities, Avista opposes adjusting (i.e., increasing) avoided cost rates in
22 exchange for obtaining the RECs. It is my understanding that under PURPA it is not
23 appropriate to include the value of RECs in avoided cost rates. Moreover, such an
9
Case No. GNR-E-1 1-03 97 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
I adjustment could create an opportunity for QF developers to arbitrage the REC value to
2 the detriment of utility customers. Further, the market for RECs is very volatile and is
3 not liquid or transparent.
4
5 Testimony of Twin Falls Canal Company and North Side Canal Company (TFCNSC)
6 Q. Please summarize your views on the direct testimony of the TFCNSC
7 companies.
8 A. Table R2 summarizes the positions of the TFCNSC, and Avista's
9 responses to them. Avista has not re-visited those positions advocated by TFCNSC
10 where it already has addressed them above in response to Staff positions.
11
12 Table R2 - Summary of Avista Responses to TFCNSC
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No. TFCNSC Position Avista Position
1 Limitations on adjustments in IRP
methodology Oppose
2 Use forwards for gas prices Oppose
3 LOLP method to determine utility need Oppose
4 Levelize capacity payments over contract
term Support, with modification
Pay capacity only during peak months and
hours Oppose
6 Capacity payment for "follow-on" QF
contracts
Oppose, but recommend an
alternative
7 Mark-to-market delay security damages Oppose
14
15 Q. Witness Schoenbeck, on behalf of TFCNSC, recommends limiting
16 adjustments to the IRP methodology between IRP publications. Do you agree?
17 A. No. The IRP methodology is just that, a methodology. To the extent that
18 assumptions affecting the results of the IRP methodology change between IRPs, those
19 assumptions should be modified. Changes should not be limited to gas prices and QF
10
Case No. GNR-E-1 1-03 98 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
L
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1 contracts. Other considerations should be made, including but not limited to non-QF
2 contracts and load forecast changes.
3 Q. Should gas prices used in setting avoided cost rates be tied exclusively
4 to forward contracts and extended as recommended by Mr. Schoenbeck?
5 A. No. Utilities use various methods to estimate future natural gas prices.
6 Avista, for example, melds short-term forward prices with third-party long-term
7 fundamentals-based natural gas price forecasts for its long-term plans. Avista sees no
8 reason to change this approach and create another set of analyses limiting its ability to
9 estimate natural gas prices. As stated earlier in my testimony for the SAR methodology,
10 Avista supports Commission Staff in the use of the ELk Mountain natural gas price
11 forecast.
12 Q. Do you support the TFCNSC recommendation that a LOLP
13 methodology be used to determine utility need?
14 A. No. Avista continues to evaluate the benefits of loss-of-load-probability
15 (LOLP) analysis for use in its integrated resource planning processes. However, it has
16 significant concerns with its application. Specifically, LOLP analysis is very sensitive to
17 the assumed availability of market purchases and sales. Even fairly modest limits on
18 market availability will affect utility positions, thereby opening the utility up to potential
19 criticism on this key LOLP assumption. Avista believes that resource need should be
20 determined using methods from the IRP.
21 Q. Mr. Schoenbeck advocates levelizing capacity payments over the term
22 of the QF contract. Do you agree?
. Case No. GNR-E-1 1-03
June 29, 2012
11
99 Kalich, C. (Di-Reb)
Avista Corporation
i•
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1 A. Yes, but not exactly as Mr. Schoenbeck proposes. QF developers
2 currently have the option to levelize their rates over the term of their contracts, but to do
3 so they must protect customers by posting liquidated damages. The amount of liquidated
4 damages is based on the mark-to-market difference between current forward prices and
5 the contract price. If the QF developer is not willing or able to post liquidated damages,
6 the developer can elect "non-levelized" payments tied to the anticipated annual avoided

7 costs of the utility.

8 I understand Mr. Schoenbeck's desire to levelize capacity payments over the
9 contract term, especially in light of the potential that no capacity payments will be made

10 in early contract years where a utility is surplus and resource ownership costs generally

11 are higher; however, any such levelization should occur only with the backing of
12 sufficient liquidated damages to the extent that utility customers are paying higher prices

13 in earlier years relative to true avoided costs.

14 Q. Does Avista support Mr. Schoenbeck's proposal to make capacity
15 payments only during utility peak months and hours?

16 A. No. Although this method likely would benefit utility customers in that
17 QF developers would not be paid during periods of outages in peak months and times, the
18 complexity of implementing Mr. Schoenbeck's proposal would, in my opinion, outweigh
19 the benefits. Utility peak planning looks at generic peak periods that likely would be

20 difficult to translate to specific hours or months. The Avista proposal, as described in my

21 direct testimony, provides similar value without requiring the complication of identifying
22 specific months and hours.
12
Case No. GNR-E-11-03 100 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
1 Q. Does Avista agree with TFCNSC that "follow-on" QF contracts
2 should receive capacity payments in all years as described in Mr. Schoenbeck's
3 testimony?
4 A. No, but Avista could support a modification of Mr. Schoenbeck's
5 proposal. Mr. Schoenbeck believes that any existing QF opting to re-contract with the
6 utility should receive capacity payments. Presumably this is because he believes
7 exclusion of the QF would cause the utility's load and resource balance to immediately
8 become deficient absent its deliveries. This might or might not be true, depending on the
9 net position of the utility's load and resource balance and the size of the QF resource.
10 Because it is possible that, even without the capacity contribution of an existing QF
11 contract, the utility would not need capacity, capacity payments should not be granted
12 unilaterally when a new contract is signed. Instead, the utility load and resource balance
13 should be modified for the loss of the QF contract, and the capacity payments based on
14 the adjusted position. This approach ensures that utility customers do not overpay for
15 capacity, and that QF resource capacity is not double-counted to the detriment of the QF.
16 Q. Do you support Mr. Schoenbeck's mark-to-market proposal for delay
17 security?
18 A. No. As described in more detail in my direct testimony, this method has
19 the potential to weaken developer performance incentives. A mark-to-market method
20 would allow a developer to avoid posting delay security where market prices are high
21 relative to the PURPA rates. In this case there is less incentive to complete a project, and
22 other factors (e.g., falling wind turbine prices) might cause the developer to delay its
23 project. This would run counter to the utility's need to have a QF developer perform.
• 13
Case No. GNR-E-1 1-03 101 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
•1
2 Testimony of Clearwater Paper, JR Simplot, and Exergy Development Group
3 Q. Please summarize your views on the direct testimony of Clearwater
4 Paper, JR Simplot, and Exergy Development Group (CP/JRSIEDG).
5 A. Already I have addressed most of CP/JRSIEDG positions in my testimony
6 above; I will not repeat myself. I do, however, wish to respond to a few additional issues
7 raised in Dr. Reading's direct testimony.
8 Q. On page 19, Dr. Reading asserts that by bifurcating capacity
9 payments from energy payments, as you advocate in your direct testimony, you are
10 "solving problems that do not exist." Do you agree?
11 A. No. For example, wind QFs generally do not contribute during system
12 peaks. Accordingly, developers of such projects today are inappropriately benefitting
13 from a PIJRPA rate methodology that ignores the capacity contribution of the QF
14 resource when determining avoided cost. However, and as my direct testimony and that
15 of others in this case explain, without recognizing the inherent differences in capacity
16 contribution between resources, the avoided cost rates (either published or calculated by
17 the IRP methodology) do not reflect the actual avoided costs associated with a specific
18 QF. Table 4 from my direct testimony illustrates how wind developers are being
19 significantly over-compensated while other project types, such as drop-canal
20 hydroelectricity, are being under-compensated for their capacity contributions. Summary
21 statistics from that table are shown below in Table R3.
22
• 14
Case No. GNR-E-1 1-03 102 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
U
1 Table R3 - Published QF Rate Comparison
2
3 6 Overpayment% 0.0% -3.0946 -61.3% -6.1% 40.1% line S/ line 4
4 Wind projects are being over-compensated by approximately 40%. This
5 compares to drop-canal hydro being under-compensated by approximately 60%.
6 Geothermal and solar are being under-compensated as well. Table R3 shows that wind
7 developers are the beneficiaries of the existing published rate structure at the expense of
8 retail customers. Table R3 makes it clear that there is a problem with making capacity
9 payments to resources that provide little or no capacity; I am hopeful that this proceeding
10 will bring PURPA rates more in-line with true avoided costs by bifurcating capacity and
11 energy payments.
12 Q. Beginning at line 3 of page 32 of Dr. Reading asserts that utility IRP
13 methodology rates "are significantly lower than the costs of building the utilities'
14 own resources." On page 34 he presents a table in support of his assertion. Do you
15 have any concerns with this table and Dr. Reading's conclusions based on it?
16 A. Yes. To purportedly show how unfair the utilities have been to QF
17 developers, Dr. Reading compares an updated (i.e., with current natural gas price
18 estimates) IRP methodology-based rate with dated rates and resource costs calculated
19 when natural gas prices were much higher. Obviously, given the significant decrease in
20 natural gas prices over the past two years, such a comparison is misleading at best.
• From Table 4 of Kalich Direct Testimony in GNR-1 1-03, at page 25, line 2.
15
Case No. GNR-E-1 1-03 103 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
.
Line Item SAR Geo Hydro Solar Wind Note
1 Energy Payment ($/MWh) 45.45 45.45 45.45 45.45 45.45 from present Avista schedule
2 Capacity Payment ($/MWh) 25.51 27.61 69.03 36.35 3.56 assumption
3 Less Integration ($/MWh) - - - (630) (6.50) line 1 * line 4 * 8,760 hrs
4 Total Payment($/MWh) 70.96 73.06 114.48 75.30 42.51 SAR line 6 * line 2/ SAR line 2
S Overpayment ($/MWh) - (2.10) (43.52) (4.34) 28.45 ISAR line 4 less line 4
0 1 Avista submitted Production Request No. 1 seeking support for Dr. Reading's
2 assertion in direct testimony at page 7, line 7, that the "SAR methodology has been
3 robust ... and has produced avoided cost rates that have proven to be remarkably accurate
4 in hindsight."4 (Emphasis added.) Dr. Reading also explained, beginning at line 20 of
5 page four of his testimony, that "the SAR methodology has been a successful, transparent
6 and effective method for estimating a utility's avoided cost rates." The CP/JRSIEDG
7 response to Production Request No. 1 provided no evidence to support Dr. Reading's
8 assertions, but instead stated that it is enough to take him at his word because he has
9 "almost three decades of experience or involvement in PURPA rate cases before the
10 Idaho Commission, and an even longer time period involved in electric utility rate cases
11 before the Idaho Commission." The response of CPIJRS/EDG to Avista's Production
12 Request No. 1 is attached hereto as Exhibit 102.
13 In addition to CP/JRS/EDG's response to Production Request No. 1,
14 CP/JRS/EDG's response to Avista's Production Request No. 2 also failed to support Dr.
15 Reading's statements, but makes clear that CP/JRS/EDG was aware of the large fall in
16 natural gas prices and the commensurate overpayment that would result absent updating
17 natural gas prices when the table was created.' When asked whether Dr. Reading's table
18 on page 34 included updated natural gas prices, the response was simply "no."
19 CP/JRS/EDG's response to Production Request No. 2 is attached hereto as Exhibit 103.
20 Falling natural gas prices is one driver of the issues in this case. Using dated
21 input assumptions, such as high natural gas prices, puts utility customers at great risk.
4 Production Request I of Avista Corporation's First Production Request to Clearwater Paper Corporation,
• J.R. Simplot Company and Exergy Development Group of Idaho.
5 Production Request 2 of Avista Corporation's First Production Request to Clearwater Paper Corporation,
J.R Simplot Company and Exergy Development Group of Idaho.
104 16
Case No. GNR-E-1 1-03 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
1 Given the misleading nature of Dr. Reading's table, the Commission should summarily
2 reject both it and all arguments based on it.
3 Q. At page 41, line 2, Dr. Reading attempts to use the Company's
4 Reardan project to support his position that delay damages are unfair to QF
5 developers. Do you have any concerns with this comparison?
6 A. Yes. Dr. Reading implies that Avista's Reardan development is a proxy
7 for QF development. In other words, his position is that Reardan not being built is
8 somehow the same as a QF developer who signed a contract for deliveries, but then did
9 not complete its project. This is an apples and oranges comparison at best. Avista
10 customers never were obligated to purchase the Reardan project; such obligation
11 would/could occur only after a prudence review by the Commission. Customers also
12 only would pay the actual costs of Reardan were it completed, unlike QF developers who
13 can arbitrage PURPA rates to make a profit.
14 Dr. Reading also misuses the Reardan project to support his desire to free QF
15 developers from honoring their delivery obligations with delay security. In another
16 misunderstanding of what defines the beginning of construction, he implies that Reardan
17 construction began in 2008 by referencing an accounting order allowing a carrying
18 charge on investments in the Reardan site.6 Construction never was started on Reardan.
19 Q. On page 65, beginning at line 10, Dr. Reading recommends that the
20 Commission adopt a non-firm standard tariff for QF power. Do you have any
21 comments on this recommendation?
6 Dr Reading's first misunderstanding was illustrated earlier in my testimony by documenting his client's
(Exergy) own press releases on its construction timelines of recent Idaho wind projects. These press • releases support Avista's position that QF construction can be completed in less than two years.
17
Case No. GNR-E- 11-03 105 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
I A. Yes. As explained in earlier testimony, Avista supports a separate
2 proceeding to adopt a tariff similar to PacifiCorp's proposed Schedule 38 that would
3 define QF contracting procedures, but does not believe such work should be a part of this
4 case. Further, it is important to point out that contrary to Dr. Reading's testimony,
5 Avista's Schedule 62 contains a standard offer for non-firm QF power.
6 Q. Does this conclude your rebuttal testimony?
7 A. Yes.
18
Case No. GNR-E-1 1-03
106 Kalich, C. (Di-Reb)
June 29, 2012 Avista Corporation
(The following proceedings were had in
open hearing.)
(Avista Corporation Exhibit Nos. 101
through 103, having been premarked for identification, were
admitted into evidence.)
COMMISSIONER SMITH: Before we begin with cross,
can everyone hear Mr. Kalich? No.
Do you have a volume button there? Can you get
closer to your mic?
THE WITNESS: Does that help?
COMMISSIONER SMITH: I don't know. Maybe it will
pull towards you.
THE WITNESS: I can also speak much louder.
COMMISSIONER SMITH: That could be the key.
MS. SA55ER: Madam Chair, if I --
COMMISSIONER SMITH: Ms. Sasser.
MS. 5ASSER: Did the Commission intend to make a
ruling on the late Intervention filed by I believe it was First
Wind (sic), LLC?
COMMISSIONER SMITH: I would have if someone had
brought that up during the preliminary matters.
MS. SASSER: I apologize for waiting until
Mr. Kalich got on the stand.
COMMISSIONER SMITH: We do have a Petition filed
on August 2nd for Idaho Winds, LLC, to intervene. It's my.
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HEDRICK COURT REPORTING KALICH (Di)
P. 0. BOX 578, BOISE, ID 83701 Avista

1 intention, I think, and the Commission's decision to deny that

2 Petition to Intervene as being too far out of time. The
3 Petition seems to be made on the assumption that they could
4 possibly be negatively impacted by a Decision the Commission
5 might make in this case, and our thought is that if ultimately
6 there is some negative impact, then certainly they would have

7 the opportunity to petition for reconsideration and point out

8 that negative impact, but that at this point in the game, it's

9 too late for more Intervenors. So with that, the Commission

10 would deny that Petition.

11 MS. SASSER: Thank you.

12 COMMISSIONER SMITH: All right. Now, we're ready

13 for cross of Mr. Kalich. Mr. Walker.

14 MR. WALKER: Thank you, Madam Chair.
15

16 CROSS-EXAMINATION
17

18 BY MR. WALKER:

19 Q. Good morning, Mr. Kalich.

20 A. Good morning.

21
Q. Mr. Kalich, could you -- could you tell us, if
WM you know, how many -- how many contracts Avista has with PURPA

23 QF projects?

24 A. I don't have that data specifically in front of
.
25 me. I could speak to the volume but probably not to the number
HEDRICK COURT REPORTING KALICH (X)
P. 0. BOX 578, BOISE, ID 83701 Avista
of contracts, but certainly it's under a dozen.
Q. Do you know how many megawatts that represents?
A. Approximately, 80 megawatts.
Q. And is that a system-wide number?
A. That would be a system-wide number for Avista,
yes.
Q. Do you know the breakdown between your
jurisdictions?
A. It's substantially Idaho. We have some -- it's
probably at least three-quarters Idaho.
MR. WALKER: I have no further questions for
Mr. Kalich, Madam Chair.
COMMISSIONER SMITH: Mr. Solander.
MR. SOLANDER: Thank you.
CROSS-EXAMINATION
BY MR. SOLANDER:
Q. Mr. Kalich, would it be problematic for Avista,
in its use of the AURORA model, if the model did not update
electric prices when gas prices are updated?
A. Yes. I -- in reading the testimony, the folks
like Avista that use AURORA, the product of AURORA in addition
to doing the portfolio analysis that's so essential to the IRP
methodology generates electricity prices, so it is important to
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HEDRICK COURT REPORTING KALICH (X)
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1 the extent if, for example, the GRID model -- which I
2 understand PacifiCorp uses. My understanding is GRID actually
3 takes as input both gas and electricity prices, so I don't
4 believe that a gas price change in the GRID model would
5 commence or would be the same result as you get out of AURORA,
6 and you would likely have to update the electricity prices as
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8 MR. SOLANDER: Thank you. I have no further
9 questions.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: Let me try this and see if it works.
CROSS-EXAMINATION
BY MR. OTTO:
Q. Good morning, Mr. Kalich.
A. Good morning.
Q. You testified in your direct testimony that PURPA
avoided cost should not -- is not an appropriate place to value
renewable energy credits. Is that true?
A. Generally, yes. I just would like to emphasize
Avista has taken no position on ownership of RECs in this
case.
MR. OTTO: Okay, that's all I have.
COMMISSIONER SMITH: Mr. Miller.
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HEDRICK COURT REPORTING KALICH (X)
P. 0. BOX 578, BOISE, ID 83701 Avista
0 1 1 MR. KEN MILLER: Just one question.
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CROSS-EXAMINATION
BY MR. KEN MILLER:
Q. Good morning, Mr. Kalich. On page 6 of your
rebuttal -- I believe it's page 6 -- you were asked about
Mr. Sterling's comment --
MS. SASSER: Madam Chair.
COMMISSIONER SMITH: Ms. Sasser.
MS. SASSER: I would object to Mr. Miller asking
the witness any questions, as a nonattorney in the case.
Pursuant to Rule 43 of the Commission's Rules of Procedures,
the organization needs an attorney in order to participate in a
technical hearing.
COMMISSIONER SMITH: So, Mr. Miller, is your
organization -- what kind of organization is yours? Is it a
corporation or --
MR. KEN MILLER: We're a 501(c) (3) nonprofit
organization.
COMMISSIONER SMITH: Nonprofit. Well, according
to our Rule 43, subsection 02 -- which I would point out was
done in response to the Commission being sued by the Idaho
State Bar for allowing nonattorneys to represent people in our
proceedings, and so we're very careful about this -- it says:
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HEDRICK COURT REPORTING KALICH (X)
P. 0. BOX 578, BOISE, ID 83701 Avista
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The representation of parties at quasi-judicial
proceedings for the purpose of adjudicating the legal rights or
duties of a party is restricted as set out below. These
include matters such as formal complaints, petitions, motions,
applications for modified procedure, or technical/evidentiary
hearings. So that's what we have. Representation of parties
at these types of proceedings shall be as follows:
A natural person may represent himself, or be
represented by a licensed attorney. A partnership or
corporation shall be represented by a licensed attorney. A
municipal corporation; state, federal, tribal, or local
government agency; an unincorporated association; a nonprofit
organization, or other entities shall be represented by a
licensed attorney.
So, I think Ms. Sasser is correct, that according
to the Rules, you can't cross-examine unless you have a lawyer.
MR. KEN MILLER: Thank you, Madam Chairman. I'll
reserve the question for a comment.
COMMISSIONER SMITH: Thank you.
Ms. Nelson.
MS. NELSON: Thank you, Madam Chair. I do not
have any questions for Mr. Kalich.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Thank you, Madam Chairman. I
have a couple of questions for Mr. Kalich.
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CROSS-EXAMINATION
BY MR. RICHARDSON:
Q. Good morning, Mr. Kalich.
A. Good morning, Mr. Richardson.
Q. Would you turn to page 5 of your direct
testimony. Referencing Footnote No. 1 on page 5, you state
that it can be argued that QF developers have adequate access
to the marketplace absent PURPA. Do you see that?
A. Yes.
Q. Did you put that in a footnote because you don't
really believe that today's QFs actually have access to the
competitive market?
MR. ANDREA: Objection: Argumentative.
COMMISSIONER SMITH: Mr. Richardson, that
objection was that your question is argumentative.
MR. RICHARDSON: I'll rephrase the question,
Madam Chairman.
Q. BY MR. RICHARDSON: Why did you put that in a
footnote rather than the text?
A. In thinking back about it, I don't know that I
can answer that question directly. There was no specific
reason for it, Mr. Richardson.
Q. So it should carry as much weight as far as the
reader of your testimony as if it were in the body of your
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1 testimony?

2 A. Sure.

3
Q. And you cite to, in that footnote, to two

4
different ways that QFS have access to the marketplace.

5 Correct?
6 Well, first you note that, quote: Utilities

7 generally procure new long-term supplies of electricity through

8 regulated or quasi-regulated competitive acquisition processes

9 that QF developers can bid into.

10 Do you see that?

11 A. Yes.

12
Q. Forgive me the characterization, but a "regulated

9 13 competitive acquisition process" sounds like an oxymoron to me.
14 Can you tell me exactly what a regulated competitive

15 acquisition process is?

16 A. Certainly. One example would be in the -- we

17 have not in recent times used the full extent of the regulatory

18 process, but I'll give you an example.

19 That is where the Utility would draft -- and I

20 think it's more specifically under our regulation in
21 Washington -- an integrate- -- or, a request for proposals that

22 is submitted to the Commission, put out for public comment.
23 Once the public comments are received, any modifications that

24 are necessary are done, there may be another filing.

25 But assume for the moment that there were no
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changes. Then it would be issued underneath that process.
And then, ultimately, the evaluation is audited,
reviewed, in participation by Utility -- or, excuse me,
Commission Staff.
Q. So the regulated part of the regulated
competitive acquisition process is based on Washington State's
rules on REPs?
A. We are regulated and procure resources for both
Idaho and Washington in electricity, so in that case, it would
be the Washington rules there, that's true.
Q. Are you familiar with Idaho's competitive
procurement rules?
A. You may be alluding to the fact that there are
not the specific rules that there are in Washington.
Q. I'm sorry?
A. I think you're saying or suggesting that there
are not similar rules in Idaho, and I believe that is true.
Q. Well, are there rules in Idaho?
A. Not specific to this process or to an IRE.
Q. Are there competitive procurement rules in
Idaho?
A. You'll see in my testimony, it talks about
regulated and quasi-regulated. And what I mean by
quasi-regulated is the fact that the Commission Staffs are
involved. We generally hire a third-party independent reviewer
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on the REP to look at the results and ensure that the analysis
was fair to the parties. And, ultimately, in order for us to
put those resources into rate base, we have to get approval by
the Commission.
Q. But the question was are there competitive
procurement rules in Idaho that Avista has to comply with in
order to acquire a new resource?
MR. ANDREA: I'm going to object on the grounds
that it's calling for a legal conclusion. It's beyond the
scope of Mr. Kalich's testimony as well.
MR. RICHARDSON: I didn't hear the objection.
COMMISSIONER SMITH: Oh. He objects that it
calls for a legal conclusion and it's beyond the scope of the
witness's testimony.
MR. RICHARDSON: Well, the witness is talking
about regulating competitive procurement processes, and I'm
trying to understand his testimony. I'm trying to understand
what he means by "regulated," and if he knows that there is a
regulated, or not, competitive procurement process in Idaho.
MR. ANDREA: And you asked him if there was a
rule that he has to follow, and that is a legal question.
MR. RICHARDSON: Doesn't "regulated" imply that
there's a rule?
COMMISSIONER SMITH: Okay, so, Mr. Kalich, I
think that what Mr. Richardson wants you to do is to describe
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the rules and processes that you're aware of in Idaho. We'll

2 see if that satisfies it.

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THE WITNESS: I don't believe there's a specific

4 set of rules in Idaho, Mr. Richardson.

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Q. BY MR. RICHARDSON: So then we have to rely on
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Washington State's rules to ensure that there's a regulated

7 competitive procurement process in Idaho then. Right?

8 A. Again, any resource acquisition that we make, as

9 a Utility, is regulated by this Commission, including the

10 process of procurement, and that, in and of itself, provides a

11 fully substantial discipline of the Utility in RFP processes.

12 I believe that even though I mentioned earlier in Washington we

S 13 didn't necessarily go through the full set of competitive

14 process, we essentially followed the letter or the intent of

15 the rules. So just due to the fact of needing to get

16 regulatory recovery, we have every incentive to do a

17 competitive process.

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Q. Are you aware that the Idaho Commission has
19 actually said that there is a clear need for a proceeding to

20 consider RFP competitive bidding rules and guidelines in

21 Idaho?
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Bench?
A. I'm not.
MR. RICHARDSON: Madam Chair, may we approach the
COMMISSIONER SMITH: You may.
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MR. RICHARDSON: Thank you, Madam Chairman. I'm
going to ask our summer clerk, Ms. Cromwell, with help in
handing out the exhibits.
COMMISSIONER SMITH: That's acceptable.
MR. RICHARDSON: Thank you, Madam Chair.
Madam Chair, we're handing out an exhibit that I
would like to be marked as Exhibit 509, which is the first page
and page 30 of IPUC Order No. 30892 from Case IPC-E-09-03.
COMMISSIONER SMITH: So it's one page of a
Commission Order.
MR. RICHARDSON: Yes, the first page and page 30
of a Commission Order. The first page is included just for
reference purposes.
(Clearwater Paper Corporation, et al,
Exhibit No. 509 was marked for identification.)
Q. BY MR. RICHARDSON: Mr. Kalich, would you take a
moment to familiarize yourself with that Order?
A. Are you referring specifically to the Commission
Findings on the second page or --
Q. I would direct your attention to page 30, the
second page of Exhibit 509, under Commission's Findings, yes.
A. Thank you.
Q. There's an underscored portion there. Would you
read that into the record for me, please?
A. I don't see anything being underscored on this
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Q. Oh, I underscored it for me, I guess. If you
would look at, read that paragraph, skip the first sentence
under Commission Findings and read the sentence beginning "The
RFP process" down through the second two sentences into it?
A. And by this, you're referring to an RFP process
Avista went through?
Q. No, this is not an Avista RFP process.
A. Okay, so just generally read it. All right.
"The RFP process was criticized by nearly all
parties to the case, some more stridently than others. While
we find that the process could have been more transparent, that
better guidelines could have been established, that evaluation
criteria could have been better explained, that the third-party
consultant could have brought more value to the process by
performing all the tasks identified in the RFP, and that the
total universe of potential bidders was perhaps not realized,
we find that the RFP process was, nevertheless, adequate."
Q. And do you know if the Idaho Commission ever
opened a docket to review competitive procurement rules in
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A. I do not know.
Q. So, one of your jobs is to assist Avista in
acquiring new resources. Correct?
A. Yes.
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Q. So you would be familiar with competitive
procurement proceedings in Idaho, would you not?
A. Sure.
Q. Now, still on your Footnote No. 1 on page 5 of
your direct testimony, you provide a second example of how QF
developers can have adequate access to the marketplace absent
PURPA. And you state that, quote:
Federal laws and regulations also now obligate
Utilities to sell or build transmission capacity to or for
third parties, enabling QF developers to sell their output to
other Utility systems or at the major trading hubs.
Do you see that?
A. Yes.
Q. What federal laws and regulations are you
referring to?
A. Mr. Richardson, that was a general statement.
There's a number of laws and rules that I don't have, nor am I
prepared to speak to today.
Q. You don't have any of those in mind?
A. Not those references specifically, no.
Q. Would that refresh your memory if they required
you to file an open access transmission tariff?
A. Are you suggesting that the -- just for
clarification, you're asking if a QF has to file an open access
transmission tariff?
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Q. No, I'm asking if Avista has to file an open
2 access transmission tariff.
3 A. We have one, yes.
4 Q. And that's required by one of the federal laws
5 you were referring to?
6 A. Certainly.
7
Q. And it's your position that this open access
8

transmission tariff enables QF developers to sell to other
Utility systems?
A. Yes.
Q. And how does that work?
A. Generally -- and, again, I'm not prepared with
all the details today -- but, generally, a request is made of
the Utility for that transmission capacity to the transmission
group.
Just to be clear, I'm not a transmission
representative of Avista, I work in the resource merchant side,
but my understanding, a request is made. The Utility takes a
FERC-identified period of time to review the application and do
preliminary studies, put together an assessment of the
availability of transmission, and to the extent if there is
available transmission, a contract is tendered to provide that
capacity. To the extent there is not enough capacity, the
transmission section of the Utility will then work with the
developer to put together a plan of action to enhance the
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transmission system to allow the flow of power off the system.
Q. So a developer in your service territory then can
physically move their electricity off your system to another
Utility to sell it. Is that generally what happens?
A. "To another Utility." I suppose to the extent a
nonUtility had assets they could also wheel to someone else,
but to a major trading hub, to another Utility, et cetera, yes.
Q. So let's say a landfill gas QF wants to use your
system to sell its output to another Utility in another state.
Would that be possible?
A. Sure. Yes.
Q. So how is that working out for Kootenai Electric
QF, that project up in your neck of the woods?
MR. ANDREA: Objection: That's not relevant.
That's beyond the scope.
COMMISSIONER SMITH: Sustained.
Q. BY MR. RICHARDSON: Are you aware that
Idaho Power is attempting to prevent QFs in your service
territory from moving electricity on your oak out of your
system?
A. I'm not involved in that proceeding.
Q. Are you aware of that?
MR. ANDREA: Madam Chair, objection. I'd like to
have a standing objection to this entire line of questioning of
Mr. Richardson.
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1 COMMISSIONER SMITH: Mr. Richardson.

2 MR. RICHARDSON: Madam Chairman, I'll move on.

3 COMMISSIONER SMITH: That's a different case and

4 you're out of line. Thank you.
5
Q. BY MR. RICHARDSON: On page 11 of your direct
6 testimony, you begin your discussion of the reasons things are

7 different today as compared to 2002 when the Commission issued

8 Order No. 29124 in which it eliminated the use of a surplus
9 period in calculating the avoided cost rates. Do you see that

10 discussion, generally?

11 A. I'm there, yes.

12
Q. Now, the very first reason provided by the
13 Commission in eliminating the first deficit year was, according

14 to your testimony, quote: The first concern was the lack of

15 regular filings before the Commission that outlined the deficit

16 year.

17 Now, you paraphrased the Commission Order there,

18 didn't you?

19 A. Yes.

20 Q. Wasn't the Commission's concern more specific

21 than just the lack of regular filings?
KPIM A. Not to my knowledge.

23
Q. Well, didn't the Commission say, and I quote:

24 Establishment of Utilities' first deficit years
r 25 requires regular filings by the Utilities, followed by
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Commission Orders. None of the Utilities have made a filing to
update its first deficit year since the first deficit years
were last established in 1996.
Does that sound familiar to you?
A. That actually sounds somewhat familiar to the
proceedings. I participated in that case, yeah.
Q. That was from Order No. 29124, at page 6.
A. Yes.
Q. Now, you say that things have changed, because at
page 11, line 4, of your testimony, quote: Utilities now file
biannual IRPs outlining future deficit years explicitly.
Do you see that?
A. Yes.
Q. Isn't it true that your Company has filed an
integrated resource plan every two years since 1989?
A. No, that isn't true. We do have, in fact, if you
go to our Web site, there is an archive back to 1989, that's
true. I think if you go back prior to 2003, you'll see some
annual updates and a number of years where IRPs weren't
published. During that period of time when the deregulation
was occurring, many Utilities, including Avista, substantially
ramped down their IRP processes, and in many cases they became
much different than they would -- originally they were intended
for and what they now have become in the past decade. So if
you looked -- and back again to that case -- it was not very
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clear in the documents that were filed in that era what our
load and resource position was at that time.
Q. So you're saying to me that you didn't -- Avista
never filed IRP5 before 2002?
A. Well, first of all, I point out that they were
not called integrated resource plans. They were substantially
load and resource balances.
My experience with Avista started in 2000, which
is when we did an update -- we called it an update -- to our
1997 IRP, and that was a very limited effort, essentially, to
update the load and resource balance; and there was not much of
a public process similar to what there is today where we have
the participation of Utility -- peer Utility staff, the
Commission Staff, Intervenors, we've had QF developers, wind
developers, a number of experts come in and review -- Power
Council, for example -- actually review all of the process of
the IRP. There's just a night and day difference between 2002
and 2012 when it comes to Utility resource planning.
Q. And one of the requirements the Commission found
was lacking was not just regular filings, but that those
filings had to be followed by Commission Orders. Do you recall
that?
A. Well, I do recall the portion that you just read
requiring Commission Order, yes.
Q. What do you think those Orders were supposed to
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contain?
A. Presumably, an acknowledgement of our integrated
resource plan, which would be the entire plan which would
include the load and resource balance contained within it.
Q. Doesn't the Commission's concern about lack of
Orders suggest that they were looking for a contested filing
with actual parties, as opposed to merely -- and to quote
you -- "other interested stakeholders"?
MR. ANDREA: Objection: Calls for speculation.
COMMISSIONER SMITH: I think you're asking this
witness to read the minds of past and maybe present
Commissioners, Mr. Richardson. I don't think that's possible
for the witness.
MR. RICHARDSON: Thank you, Madam Chair.
Q. BY MR. RICHARDSON: Mr. Kalich, have you ever
read one of the Commission's Orders in an IRP filing?
A. I know exactly where you're going. There is no
specific Order in Idaho on an integrated resource plan, it's an
acknowledgment letter. And I have read each of the
acknowledgment letters.
Q. Then you must know that every one of those Orders
contains a disclaimer to the effect that, quote: Based on our
review, we find it reasonable to accept the Company's electric
integrated resource plan. Our acceptance of the IRP should not
be interpreted as an endorsement of any particular element of
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the plan, nor does it constitute approval of any resource
acquisition or proposed action in the plan.
And you're aware of that language?
A. Yes, sir.
Q. Now, suppose the Commission used that language
when you filed for a certificate of convenience and necessity
to build a new gas plant. Do you think you could take that to
the bank and finance it?
MR. ANDREA: Objection: Speculative.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Madam Chair, I think it's a
legitimate question, because this Utility is asking you to set
avoided cost rates based on an IRP that the Commission never
approves. And so I'm just asking if the shoe were on the other
foot, whether or not this Utility would be able to conduct
business.
COMMISSIONER SMITH: Okay. Do you understand the
question, Mr. Kalich?
THE WITNESS: Maybe I'd ask him to repeat it
again.
COMMISSIONER SMITH: Okay, try and -- try and ask
that question you just formulated.
Q. BY MR. RICHARDSON: Now suppose the Commission
used that equivocal language when it was considering a request
by your Utility to build a new plant for a certificate of
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1 convenience and necessity. Would you be able to take that
2 Order to Wall Street and finance that plant?
3 A. We might make a reasonably simple filing to ask
4 the Commission to make an Order on that specific part that was
5 pertinent to the issue at hand.
6
Q. So the answer is, no, you would need that more
7 specific language?
8 A. Yes.
9
Q. Now --
10 MR. ANDREA: I'd like to renew my objection to
11 that last line of questioning: It was hypothetical, it's
12 beyond the scope of Mr. Kalich's expertise or his testimony.
13 COMMISSIONER SMITH: So noted.
14
Q. BY MR. RICHARDSON: Mr. Kalich, on page 13
15 towards the bottom of the page of your direct testimony, you
16 characterize the seventh reason for the Commission's ruling
17 that surplus periods not be counted when setting avoided cost
18 rates, thus, quote: The seventh concern was that Utilities
19 tend to be surplus in the near term, and that avoided cost
20 rates should not provide incentives for a Utility to increase
21 its length to avoid having to purchase PURPA power.
22 Do you see that?
23 A. Yes.
24
Q. And once again, you paraphrased the Commission,
25 didn't you?
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A. I only provided a portion of what was in the
Order, yes.
Q. What the Commission actually said in its Order is
that, quote: Utilities always plan to be surplus in the short
term.
The Commission didn't equivocate by expressing
the concern about a tendency to be surplus, did it?
A. Well, to that first point, I would disagree with
the statement. I think it's pretty clear a number of Utilities
are --
Could you repeat the question, please?
Q. Yes. I wasn't asking you if you agreed with the
statement. I was asking you what the Commission's Order said.
What the Commission actually said in its Order is
that, quote: Utilities always plan to be surplus in the short
term.
A. Yes, I paraphrase that Utilities tend to be
surplus. And probably call it a mistake or not, the reality of
what I was reading from the Commission Order and what actually
is out there in the marketplace, I think you would say
Utilities do tend to be surplus in the near term. However,
there are a number of Utilities that are not surplus in the
near term. Avista is not one of those Utilities; we are. So I
used that description of what I believe to be what's happening
in the marketplace today.
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Q. Wouldn't you agree that there are significantly
2 different implications when you use the word "tend to be
3 surplus" as opposed to "always in surplus"?
4 A. There is a clear difference between those two
phrases.
Q. In the Commission's Order eliminating the deficit
year in calculating the avoided cost rates, the Commission had
this to say about IRPs --
MR. ANDREA: Madam Chair, I'm going to object at
this point. I've been trying to be patient, but Mr. Richardson
is trying to enter new evidence into the record through his
cross-examination.
MR. RICHARDSON: Madam Chair, the witness's
testimony's foundation is your Order. I'm asking about his
foundation of his testimony. It's -- the genesis of his
testimony is your Order.
COMMISSIONER SMITH: I am going to allow the
question.
MR. RICHARDSON: Thank you, Madam Chair.
Q. BY MR. RICHARDSON: Mr. Kalich, in the
Commission's Order eliminating the deficit year in calculating
avoided cost rates, the Commission had this to say about IRPs,
quote:
As a consequence, Company IRPs almost never
accurately reflect a Utility's actual surplus/deficit
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situation. As the Utilities candidly admit, their
load/resource balances are not static numbers, but can change
day to day.
And that's Order No. 29124, page 8.
You would agree, wouldn't you, Mr. Kalich, that
the Commission got it right when it said that, and that that
statement is as true today as when it was first written?
A. I can't say that Avista agreed with that summary
from that hearing back in 2002. We were rather disappointed
that the Commission came to that conclusion.
Back to my earlier statement, IRP5 in 2012,
2011 -- pick your years in the last decade -- are substantially
different than they were back then. You could almost argue
that there would be really no comparison between the two
planning documents, the processes that support the IRP5.
There's much more rigorous evaluation and critique of these
documents. So I think any evaluation in 2002 and prior to that
period of time are really not appropriate today.
Q. So you're pretty confident about your current
I RP?
A. I think we do a wonderful job.
Q. And you're familiar with your current IRP?
A. I am, yes.
MR. RICHARDSON: Okay, Madam Chairman, may we
approach the Bench?
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0 1 COMMISSIONER SMITH: Certainly.
MR. RICHARDSON: Thank you, Madam Chair.
COMMISSIONER SMITH: While the documents are
being passed out, I would just note that the Order Nos. 30892,
29124, I think the Commission will take official notice of
under Rule 26301 so that it's not just random pages but it's
the whole Order.
MR. RICHARDSON: I appreciate that, Madam Chair.
Q. BY MR. RICHARDSON: Mr. Kalich, take a moment to
familiarize yourself with the document that I am going to ask
to be marked as Exhibit 510.
(Clearwater Paper Corporation, et al,
Exhibit No. 510 was marked for identification.)
Q. BY MR. RICHARDSON: Do you recognize that
document, Mr. Kalich?
A. It looks like our 2011 integrated resource plan,
or at least a few pages from it.
Q. It's eight pages from your 2011 IRP. The
document page numbers are 2-20 through 2-29. So that would be
Chapter 2 of your 2011 IRP?
A. Yes.
Q-1 Looking at this document, I'll reference you to
page 2 of the document, of the Exhibit 510. Can you tell us
from the graph in the middle of that page when the Company's
first winter and summer capacity deficit year is?
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A. I think it would be better to note this graph is
just presenting the winter capacity, so you aren't going to get
the summer or the energy deficit out of that. Probably the
more easier numbers to look at would be on page you're calling
7 of ten, which is the actual detail behind that integrative
format.
Q. Doesn't this graph graphically show the data on
the table?
A. That's the intent, yes.
Q. So let's just look at the graph and see what we
can see in terms of when your Utility is deficit.
MR. ANDREA: Madam Chair, I'm going to object to
the admission of this exhibit: There's no reason why this
could not have been included in rebuttal testimony. It's
attempting to enter new evidence way too late in the game, and
I haven't had a chance to fully review it. So I'd like to
object to the admission of this.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Madam Chair, the witness's
response to my earlier line of questioning that IRP5 have been
filed and that is one of the reasons the Commission chose to
eliminate the first deficit year, his response was, well, Our
2011 IRP is a Cadillac IRP and we rely on it, and we therefore
don't need to worry about your concerns that the Commission
expressed in its earlier Order.
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1 And I just want to explore the document. This
2 witness is intimately familiar with how that works.

3 COMMISSIONER SMITH: I didn't hear him use the

4 word "Cadillac."

5 But I'm going to allow the questions, Mr. Andrea.

6 I think the witness's testimony is based on the IRP, and this

7 is legitimate inquiry.

8 MR. RICHARDSON: Thank you, Madam Chair.

9 Q. BY MR. RICHARDSON: So the question was looking

10 at the chart here on the second page of Exhibit 510, can you

11 show me generally where the -- when Avista identifies its first

12 deficit years?

13 A. My testimony talks about the need to look at

14 three different considerations. There's winter capacity,

15 summer capacity deficit, and also in the energy. So it is
16 possible that you may have a winter deficit sooner than you

17 have a summer deficit. We're a winter-peaking Utility that

18 tends, in many cases, to drive us to a deficit.

19 Figure 214 -- referring to on the second page --

20 is our winter 18-hour capacity L and R, which is tied back to

21 actually page 2-27, or page 8 of your handout, and it states

22 clearly that the first deficit is 42 megawatts in 2020.

23 Q. In 2000 what?

24 A. For the winter deficit.

25 Q. In 2000 what?
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A. 2020.
Q. Twenty. Staying on that chart, let's look at the
top resource in the chart on page 2 of Exhibit 510. And I
copied these in color so it would be easier to identify. What
is that top, green resource in 2012?
A. That is Avista's portion of what has been
determined by the Northwest Power and Conservation Council to
be regional surplus; in other words, assets that are surplus to
the needs of the region, and surplus to the region's ability to
export those to other areas of the country.
Q. And if you look at the text above that graph,
there's a sentence four lines up that begins with the word
"adjustments" which purports to describe that resource. Would
you read that into the record for us, please?
A. Just that sentence, Mr. Richardson?
Q. Yes, please.
A. "Adjustments to the net position include market
purchases when surplus capacity exists in the Northwest, as
represented by the green bars."
Q. And there's a footnote there, No. 7. Do you see
that?
A. Yes.
Q. Can you read the first two sentences of that
footnote into the record, please?
A.

"Avista relied on work by the Northwest Power and
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Conservation Council in its resource adequacy forum exercises
to determine the level of surplus summer energy and capacity.
Reliance is limited to Avista's prorated share of regional
load."
Q. And that green bar represents roughly about
700 megawatts?
A. 7-, 800, yes, at least in the first year.
Q. Are there contracts in place today that Avista
can enforce for those 700 megawatts?
A. No.
Q. So when the term "Avista's share," quote, of this
excess capacity is used, what is really meant is Avista's
hoped-for share of this excess capacity?
A. No, not at all. There's substantial regional and
Utility analysis of the position of the region, which is
essential to prudent Utility planning. There's a huge asset
and surplus in the Northwest. That's why we're witnessing such
a low -- part of the reason we're witnessing such low prices
today.
Q. You don't have a contract for that 700 megawatts?
A. It's common Utility practice to rely
Q. The question was: You don't have a contract for
that 700 megawatts?
A. We do not have a contract today for 700
megawatts, no.
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Q. So it's a fair characterization to call it
2 hoped-for megawatts?

3 A. Absolutely not.
4 MR. RICHARDSON: Madam Chair, may we approach the

5 Bench?

6 COMMISSIONER SMITH: Certainly.

7 MR. RICHARDSON: Back to that footnote that we

8 were talking, Footnote 7, I actually went to that reference and

9 clicked on that URL site, and I'm handing out the results.

10 COMMISSIONER SMITH: This would be 511.

11 MR. RICHARDSON: This would be marked as

12 Exhibit No. 511, Madam Chair. It's entitled Pacific Northwest
.
13 Regional Resource Adequacy Assessment.

14 (Clearwater Paper Corporation, et al,

15 Exhibit No. 511 was marked for identification.)

16
Q. BY MR. RICHARDSON: Give you a moment to look at

17 the document. Mr. Kalich, are you familiar with this

18 document?

19 A. Yes, I am. It's an energy load resource
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tabulation.
Q. It's the one relied on in your IRP for the
700 megawatts of resource. Correct?
A. This doesn't appear to be the full spreadsheet.
This is only the energy balance. We're referring here to
winter capacity in Figure 2.14.
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S 1 Q. There's a similar winter capacity spreadsheet
that purports to show what you represent in your IRP?

3 A. I believe it's the same spreadsheet.

4
Q. When was the report relied on in your 2011 IRP

5 last updated?
6 A. Could you rephrase that question, please?

7
Q. Well, let me state it another way:

8 What's the date of this document? I would refer
9 you to the upper left-hand corner.

10 A. It refers to May 2008, which at the time of the

11 integrated resource plan, there was no update to that document.

12 There was no need for an update, I would suggest.
0 13
Q. So you're relying on, for your 2011 IRP, a

14 document that's four years old?

15 A. And, actually, I sit on the Resource Adequacy

16 Forum, so I'm familiar with that process. This document is
17 updated when there has been a change significant enough to

18 justify the change being made. So my -- what this means, in my
19 mind, is there have not been substantial enough changes in the
20 marketplace to warrant an update.

21
Q. So you sit on the board?

22 A. I don't sit on -- there's no board. It's an

23 advisory committee.

24
Q. You said you sat on the board, I thought.

25 A. I used the wrong term then. It's an advisory
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Q. So it's not a board?
A. No, it's not.
Q. It's the -- what is it?
A. There's a technical advisory committee on which I
sit. There's also a policy setting group; it's a separate
group I do not sit upon. But, essentially, we do most of the
work, provide input on the work that the Power Council does to
obtain these figures.
Q. So as I was looking at the Northwest Resource
Advocacy Forum, I saw a statement of purpose for how this
document is to be used, and I'll quote it for you and ask you
if you recognize this:
The purpose of the standard is to provide an
early warning should resource development fail to keep up with
demand growth, as what happened during the late 1990s, leading
up to the energy crisis of 2001.
Does that sound familiar?
A. That, I believe, was the purpose of or one of the
major purposes of this effort, yes.
Q. And they went on to warn that, quote: The
regional adequacy assessments are not intended to apply
directly to individual Utilities.
Do you recall that?
A. I think the Council generally with this document
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1 makes statements similar to that, so I would agree with that.
2 Q. And they also stated that they are not intended
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to provide a resource planning target, nor is it a surrogate
for integrated resource planning processes.
5 Do you recall that?
6 A. I agree, and it is not the basis of our
7 integrated resource plan.
8 Q. But isn't that exactly the use you're putting it
9 to here?
10 A. Not at all, Mr. Richardson. This is information
11 Avista uses independently. We evaluate the work of the Power
12 Council. We do work internally. We review the information
0 13 with our technical advisory group and, based upon that work, we
14 came to the conclusion that we could use this information.
15 I just would point out this is an energy L and R.
16 You've been explaining the capacity L and R. So it's an
17 apples-and-oranges comparison here anyway. We would need the
18 capacity portion of this spreadsheet for an apples-to-apples
19 comparison.
20 But it allows it and forms our integrated
21 resource planning process, and while we don't use the Power
22 Council's numbers explicitly, we use that as a guide to assist
23 in our planning processes.
24 Q. Referencing back to your direct testimony at
25 page 12, you are asked about the four reasons the Commission
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S 1 eliminated deficit years, which was because -- and here I will
2 quote the Commission and not your characterization of their
3 Order -- quote: Load forecasts are one-half of the

4 surplus/deficit equation. Load forecasts -- and I'm quoting
5 the Commission here -- load forecasts are prepared entirely by
6 each Utility, with little or no oversight. Utilities can

7 easily manipulate their load forecasts to produce a desired

8 result.
9 And that's Order No. 29124 at page 6. Do you

10 recall that?

11 A. While I don't recall the specific language, I'm

12 not that familiar with that Order to be able to quote it.
13 Again, I would point back to earlier responses to your

14 questions.

15 2002 and 2012 are ten years apart, and the IRP
16 processes followed today are substantially, if not

17 holistically, different than they were in 2002.

18 Q. And you're using resources not just in 2012 but

19 through 2020 to create a surplus for resource that you haven't

20 contracted for?

21 A. Avista believes it's prudent and reasonable to

22 rely on a significant regional surplus to the benefit of our

23 customers. The evaluation done by the Power Council, which we

24 confirmed and duplicated ourselves internally, showed that

25 there's substantial surplus in the marketplace, and it would be
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best for our customers to rely on a portion of that, a small
portion. And as the footnote says, we rapidly phase out the
surplus if the Comm- -- this graph, for example, that shows
7- or 800 megawatts of resource, that continues well out past
2020, but if you look at that L and R, you'll see a drastic
drop-off in the amount of surplus we rely on identified by the
Council. What we're doing there is recognizing the lack of
certainty as you go further out in time, so we're rapidly
reducing that surplus, which pushes more towards a deficit
position within the Utility.
Q. So if I were just looking at resources that you
own or contract for, you're deficit today?
A. Was that a question?
Q. That's the question.
A. I assume you're not talking about 2012, because
we are not short in 2012.
2013 we show, if you assume you have no ability
to interact with the marketplace, no ability to procure any of
that surplus power, just relying on Avista resources,
contracted resource, we would be -- looks like we would be
short approximately 20 megawatts.
Q. Today?
A. Today. And then we would be surplus in 2014.
Not today, no, Mr. Richardson. We have -- we're
in the middle of 2012. We have procured assets for the
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Q. Now that we understand the true nature of this
resource that creates a surplus for you through 2020 that you
have no legal right to, cannot call on, and cannot enforce,
isn't this the exact type of IRP manipulation the Commission
was concerned about when it eliminated the first deficit
year?
MR. ANDREA: I object to the characterization as
"manipulation."
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Instead of "manipulation," I'll
say "massage."
Manipulation is the Commission's word, not mine.
You were concerned about this very activity, and that's why you
eliminated the first deficit year.
COMMISSIONER SMITH: Mr. Richardson, now you're
characterizing what you believe the Commission's Order is.
Let's just stick with the words, because I'm not sure you've
interpreted it correctly.
MS. SASSER: Madam Chair, on that line of
thinking, I would object that Mr. Richardson is repeatedly
quoting the Commission's Orders but we don't have the benefit
pursuant to the Rule for him to have provided those Orders to
us so that we can see it in context.
MR. RICHARDSON: I'm not asking the Commission to
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take official notice or introducing the Orders. The Commission
Orders speak for themselves.
COMMISSIONER SMITH: Exactly, Mr. Richardson, so
there's no need for you to characterize them. They will speak
for themselves.
And there's no need to ask Mr. Kalich to wonder
about what the Commission said then and if that's what they
meant. So I'm going to sustain the objection.
Q. BY MR. RICHARDSON: Okay. Your IRP process is a
public process. Correct?
A. Yes, it is.
Q. And your most recent IRP states that the
technical advisory committee plays a significant role in
guiding the development of the IRP?
A. Yes.
Q. But I couldn't find a list of who was on your
technical advisory committee in the IRP. Can you tell us who's
on the technical advisory committee?
A. That actually would be in the appendix, I
believe, but I can speak generally who's there. Would that be
adequate for your line of questioning?
Q. That would be fine.
A. There are individuals from the Commission Staffs,
so from Idaho and Washington, because those are the two areas
we're regulated on our IRP for electricity; we have a number of
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1 academic folks that have interest in our integrated resource
2 planning process; the Northwest Power and Conservation Council,
3 who does a regional plan, also participates in the integrated

4 resource plan; we have a number of customers, those will be

5 some of our larger industrial customers, sometimes we'll get

6 some smaller consumer groups; usually the City of Spokane will

7 show up; developers will be there, QF and not; and then, of

8 course, Utility peers, so we'll have folks from PacifiCorp
9 and/or Puget and/or Idaho Power attend some of those meetings;

10 and then, of course, internal Utility staff.

11
Q. Are you familiar with the news recently: Idaho

12 Power kicked the Snake River Alliance off of their technical
13 advisory committee? Do you recall that?

14 MR. WALKER: Objection, Madam Chair: Perhaps

15 that would, first of all, be better off for an Idaho Power

16 witness; and, second of all, the characterization. If
17 Mr. Richardson intends to testify, maybe he should take the

18 stand.

19 COMMISSIONER SMITH: Mr. Richardson, I do think

20 you've gone beyond the scope of this witness's testimony.

21 MR. RICHARDSON: Madam Chair, I will have a

22 question for Idaho Power.

23 Q. BY MR. RICHARDSON: Do you screen who can serve

24 on your technical advisory committee based on their views of
25 what resources your Utility should acquire?
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1 A. We do not.
2
Q. Does Avista screen who can serve on its board of
3 directors based upon their view of what resources you should
4 acquire?
5 A. I wouldn't be able to answer that question,
6 Mr. Richardson.
7
Q. Now, on page 30 of your direct testimony, you
8 state that PURPA contracts can be executed -- according to your
9 proposal -- can be executed up to five years prior to
10 commercial operation dates, but that prices will only be
11 available for the two years immediately preceding the
12 commercial operation date.
13 When you use the term "contract," do you mean a
14 five-year contract that is enforceable by Avista against the QF
15 for nonperformance?
16 A. I don't think that's what I was implying there.
17 I was only talking generally in the sense of whatever contract
18 terms that the parties enter into, be it a one-year contract or
19 a 20-year contract, that, for example, if you were going to
20 enter into -- build a resource, say, in 2019, we would propose
21 that the contract not be executed until 2014 at the earliest.
22 And because that was five years and there would be a large
23 period of time between when the contract was signed and when
24 the delivery was actually occurred, we would wait until 2017 in
25 this example to provide firm, locked-in prices, but there would
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1 be an obligation on behalf of the Utility in 2014 to include
2 the QF resource in its L and R and then plan to include that as
3 part of its portfolio.
4
Q. So in 2014 in your example, that QF would be
5 obligated to make deliveries in 2019?
6 A. That's correct.
7
Q. Even though it wouldn't know what price it was
8 getting until 2017?
9 A. And if it -- I suppose if there was a concern
10 there, it could wait until 2017 to contract.
11
Q. So you don't really expect a developer to sign a
12 contract for delivery of power five years in advance without
S 13 knowing what the rate will be for three or more years? You
14 don't really expect the developer to take advantage of that, do
15 you?
16 A. I'm really looking at this from the perspective
17 of the Utility ratepayer and not from a perspective of the
18 developer. So given the large uncertainty over five years, the
19 thought here was to give the developer a little more certainty
20 around the contract. If they need to show they actually have a
21 Utility contract, we'd be willing to commit to five years ahead
22 of that commercial operation.
23 Q. You have a degree in business economics. What do
24 you think your business economics professors would think about
25 your proposal?
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MR. ANDREA: I object: Speculation.
COMMISSIONER SMITH: Mr. Richardson.
3 MR. RICHARDSON: The witness is an expert. He's
4 testifying as to how to contract.
5 MR. ANDREA: He cannot tell you what his
6 economics professors would think of something.
7 COMMISSIONER SMITH: I think you need to rephrase
your question.
MR. RICHARDSON: I'll move on, Madam Chair.
Q. BY MR. RICHARDSON: At page 31, Mr. Kalich, you
state that liquidated damages are a key protection a Utility
must have. Correct?
A. Yes.
Q. And from what, exactly, is Avista seeking
protection?
A. A Utility's I think largest concern with a QF as
far as the delivery and what the damages could be to the
Utility and its ratepayers is nonperformance in the event of
market prices moving substantially. So we've already gone
through and talked about the load and resource balance, and
when we have a deficiency, we need to go out and procure
resources ahead of time to ensure system reliability. Once
we've contracted with a QF, it's in our load and resource
balance and we act as if it's a firm resource.
To the extent a QF developer does not perform, we
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S 1 will be exposed and have to go out last minute, which isn't
2 usually the best way to procure resources. Sometimes there may
3 be an opportunity in the marketplace, but certainly a plan
4 ahead to do that type of a transaction would be a risky thing

5 to do.

6 So we've signed a contract with a QF developer.
7 We need them to perform to prevent that type of occurrence.

8 Q. I just have to ask how that relates to your
9 planning if you plan to meet load through 2020 with no

10 contracts.

11 A. I guess it would, Mr. Richardson -- it would

12 depend on the term of the QF contract. If it was a QF contract
.
13 for 2018 delivery, I would be less concerned, I suppose, but

14 most of the contracts we've seen, people are asking for 20-year
15 contracts that go well out beyond the term of our forecasted

16 surplus. And, therefore, to the extent that we lock in a

17 contract today and there's no performance and, as we've seen,
18 there may well not be any performance until we get very close

19 to that deficiency, and then we're out rushing, trying to
20 procure a resource and it may be a less than optimal time to do

21 that, and, you know -- I'll speculate no further.

22
Q. And in your answer, you said if the default was

23 like in 2018, you would have less concern. Why did you say

24 that?

25 A. I don't think that's what I said.
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1 Q. I think the court reporter could read it back.

2 (Whereupon, the requested portion of the

3 record was read by the court reporter.)

4
Q. BY MR. RICHARDSON: Does that refresh your
5 memory?

6 A. I was trying -- so you're saying in the example I

7 was providing, if our deficit was in 2020 and the QF was only

8 for 2018 delivery?

9
Q. I don't know what you were saying.

10 A. You're asking me to clarify.

11
Q. Yeah.

12 A. There would be less concern. With that, again, I

S 13 would point out that Utilities, once we have a position, we

14 will -- generally will move to address that position which

15 could include making sales based on our surplus position. We

16 do that regularly to balance our portfolio. So I said "may

17 have less concern," because there may be a position where we

18 have enough length that if the QF didn't perform for that short

19 contract, we would be in a position that maybe wouldn't be as

20 detrimental to the Utility. But to make holistic or wholesale
21 assumptions that we don't need a QF to perform would not be the

22 correct judgment there.

23
Q. You equivocate a lot on may not have as much

24 effect. Isn't it true if a QF doesn't come online on its

25 scheduled operation date, in a period where you are surplus,
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1 you're not damaged?

2 A. You're making the assumption, Mr. Richardson,

3 that we would be surplus in 2018, and actually that was

4 probably the mistake I made.

5
Q. I think that was your assumption.
6 A. Yeah, my mistake. Yeah, my mistake, I agree.

7
Q. And I'm following up on that assumption, and I'm

8 asking if a QF with a scheduled online date in your assumption,
9 2018, you're surplus, you're not damaged by that QF's failure

10 to come online, are you?

11 A. What I'm trying to explain is that there is no

12 certainty. In fact, it's very unlikely that the Utility would
13 be in a large surplus position when we got that close to

14 delivery. If the Utility made no changes to its L and R, made

15 no sales, no purchases, had no load, and there was a surplus,
16 there could be -- and I emphasize "could be" -- a potential for

17 less damage to the customers. We don't know what the damage

18 will be, we don't know what the cost will be to the Company,

19 and that's why we have delay security to ensure performance by

20 the developer.

21 What you end up seeing and what I've seen, when

22 the market prices go down, developers can sit on these projects
23 and they sit in the queue and they never become developed.

24 There's no real teeth to ensure that we actually get a

25 delivery.
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HEDRICK COURT REPORTING KALICH (X)
P. 0. BOX 578, BOISE, ID 83701 Avista
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Q. Do you recall that the Idaho Commission has
2 recently stated regarding liquidated damages that, quote: The
3 amount must be a fair and reasonable offset of a regulated
4 Utility's estimated increase in power supply costs attributable
5 to the PURPA supplier's failure to meet its contractually-
scheduled operation date?

7 And that's Order 30608 in IPC-E-08-09. Do you

8 ever recall having read that?

9 A. I'm familiar with it. I can't say I specifically

10 read it, I have a recollection of reading it, but that I recall

11 it.

12
Q. And over on page 32 of your testimony, you talk
13 about a delay liquidated damages deposit. Do you see that?

14 A. Well, I think that's one of the -- we need to be

15 clear here. There's a difference between liquidated damages
16 and delay security, and to the extent my testimony is a little

17 less clear, this line of testimony is around delay security,

18 delay liquidated damages, which I think the reference you were
19 providing was more towards liquidated damages for
20 nonperformance.

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Q. I think you refer on your testimony to delay

22 liquidated damage deposit.

23 A. We're on the same page then, sure, yeah.

24
Q. Now, this is a deposit for delay security.

25 Correct?
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A. Yes.
Q. And what happens if a project is delayed by, say,
one day?
A. Well, I think it depends the rest of the
contract. There are provisions for force majeure, so to the
extent there was a force majeure -- in other words, something
outside of the control of the QF -- presumably there would be
an extension of that online date. To the extent there was no
force majeure, the Utility would collect the delay security.
Q. If the project comes online on time, will the
deposit be returned to the developer?
MR. ANDREA: I'm going to object just because the
question really calls for Mr. Kalich to know the entire
contract and all the terms in the contract, and the answer to
that would depend upon the provisions of the contract, which we
don't have.
MR. RICHARDSON: I'll rephrase the question,
Madam Chair.
COMMISSIONER SMITH: Thank you, Mr. Richardson.
Q. BY MR. RICHARDSON: In your proposal, how do you
envision when the project comes online when or whether the
developer will get the deposit back?
A. Yeah, my testimony doesn't cover that.
Q. And do you have a vision of that?
A. I don't today, no.
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HEDRICK COURT REPORTING KALICH (X)
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Q. Now, your recommended delay security deposit is

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$45 a kW. Is that correct?

3 A. Yes.

4 Q. And what's that dollar amount if I were proposing

5 a 10 megawatt project?
6 A. Ten megawatts of energy or capacity?

7 Q. Capacity.

8 A. Of capacity. So it would be 10,000 times $45.

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Q. Be about $450,000?

10 A. Yes.

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Q. Do you agree that's a significant amount of
12 money?

13 A. "Significant" is a relative term, so --
L

14 COMMISSIONER SMITH: "Relative."

15 THE WITNESS: Relative, excuse me, a relative

16 term. Thank you, Commissioner.

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Q. BY MR. RICHARDSON: How much interest will Avista
18 pay the developer on that deposit?

19 A. I don't believe we provide any interest on that.

20
Q. So you're proposing to have a 10 megawatt QF give

21 you $450,000 when the contract is executed, and that could be,

22 according to your testimony, up to five years before the

23 commercial operation date?

24 MR. ANDREA: I object: Again, you have to look
25 at the entire contract. There may be other ways to post that
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security, just depends on the contract. So asking in a vacuum
this question in a vacuum is not correct.
MR. RICHARDSON: Madam Chair, if I may respond?
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: I'm not asking in a vacuum. I'm
asking him directly on his testimony.
COMMISSIONER SMITH: But you could recognize that
there would be different ways to structure a contract and
provide the security.
MR. RICHARDSON: According to Mr. Kalich's
testimony, the contract could be executed up to five years in
advance of the commercial operation.
COMMISSIONER SMITH: Could be.
MR. RICHARDSON: His testimony is there's a
$45 security deposit. That's in his testimony. I'm asking if
that's what he's proposing.
COMMISSIONER SMITH: Is that one of the many ways
that it could be provided, Mr. Kalich?
THE WITNESS: Yes, Commissioner.
Q. BY MR. RICHARDSON: How else do you propose for
QFs to provide deposit security if not for $450,000 cash?
MR. ANDREA: I object: There's many different
ways. Mr. Kalich doesn't structure those contracts, so there's
different ways and he shouldn't speculate on what those ways 1* 25 1 may be.
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HEDRICK COURT REPORTING KALICH (X)
P. 0. BOX 578, BOISE, ID 83701 Avista
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1 MR. RICHARDSON: Madam Chair, may I respond?

2 COMMISSIONER SMITH: Yes, Mr. Richardson.

3 MR. RICHARDSON: These mysterious different ways

4 I would like to ferret out. We're setting rules for how QF
5 developers are going to proceed and operate in the future.

6 He's only offering one method. If he's got other secret
7 methods he wants to use, that he's going to use to avoid

8 answering questions about this method, we should know what they

9 are; otherwise, this is the only thing he's proposed.

10 COMMISSIONER SMITH: Mr. Richardson, I believe

11 your characterization is -- well, it's extreme. And I know

12 you're a good lawyer, so I know that you understand that
13 lawyers can provide different terms in contracts for meeting
L4

14 the requirements, you know, for example, letters of credit or
15 other instruments that might not necessarily be cash. So I

16 don't think this witness is the right person to be talking

17 about all of the different ways that amount of security could
18 be provided in a contract between two parties.

19 MR. RICHARDSON: Mister -- thank you,

20 Madam Chair.

21 Q. MR. RICHARDSON: Mr. Kalich, on page 31 to 32 of

22 your testimony, you state that a QF developer has a free option

23 to either honor its contractual commitment, break its

24 commitment, or simply cease development where market changes

25 have changed. Do you see that?
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HEDRICK COURT REPORTING KALICH (X)
P. 0. BOX 578, BOISE, ID 83701 Avista
0 1 1 A. Absent delay security damage, yes.
2 Q. Pardon me?
3 A. Absent the delay securities I'm proposing, yes.
4 Q. Does Avista perceive this free option of electing
5 to perform or to breach the contract to be an option that is
6 generally unavailable in other contracts?
7 A. Generally, those are not available. Were they
8 made available, there would be a substantial premium charged to
9 the entity obtaining that option. In this case, it would be
10 the QF developer.
11 Q. Do all QFs impose the same risk or burden upon
12 Avista, regardless of their capacity?
13 A. Are you asking me is there some de minimis size?
14 Q. No, I'm asking if all QF5, regardless of size,
15 impose the same risk that causes you to require a delay liquid
16 security deposit.
17 A. I think the fact that the $45 is on a per-kW
18 basis reflects the fact that there would be different risks
19 associated with different sized resources.
20
Q. But the $45 per kW is the same regardless of if
21 I'm an 80 megawatt QF or a 500 kW QF?
22 A. The deposit would be prorated based on your size.
23

You would, if you're talking about 500 kilowatts, you would
be -- if you're 80 megawatts, you'd be 160 times -- you have
25 160 times size bigger deposit, if that makes sense.
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Q. But on a per-kW basis, you don't perceive any
difference in the risk Avista is assuming by contracting with a
500 kW versus an 80 megawatt QF?
A. I think for purposes of this proceeding, I think
that's a "yes."
Q. And do all QFs impose the same risk or burden
upon Avista regardless of current electric market conditions?
A. That's a pretty broad question. Some QF
developers have a substantial balance sheet, some don't. So I
don't know that I can say they all have the identical risk to
the Utility for performance.
Q. But you're imposing identical liquid security
deposit requirements on all QFs?
A. As the Chair pointed out, there are other means
besides a cash deposit. So if you do have a strong balance
sheet, that balance sheet -- and my understanding, again, as my
counsel pointed out, I don't do the contracting for that
portion of the -- for these QF contracts, but my understanding
is there are other means besides simply putting $45 per kW into
an escrow account or wherever it goes.
Q. Well, you're our only witness for Avista. Did
you have other means in mind that you didn't tell us about?
MR. ANDREA: I think that's been asked, and
objection has been made and has been sustained.
MR. RICHARDSON: I'll move on, Madam Chair.
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HEDRICK COURT REPORTING KALICH (X)
P. 0. BOX 578, BOISE, ID 83701 Avista
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Q. BY MR. RICHARDSON: Mr. Kalich, did you know that
2 both Idaho Power and Rocky Mountain Power are proposing the
3 same $45 liquid security deposit?
4 A. That's my understanding.
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Q. Doesn't it strike you as a little odd --
6 MR. SOLANDER: Objection.
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Q. BY MR. RICHARDSON: -- that every Utility in the
8 state of Idaho in every QF project, no matter how large, no
9 matter how small, no matter the market conditions, no matter
10 the type or mode of force, all impose the identical risk on all
11 of the Utilities?
12 MR. ANDREA: I object to the characterization as
13 "odd." I object to the question as well.
14 Q. BY MR. RICHARDSON: I'll replace the word "odd"
15 with "unusual," Mr. Kalich. I think it's a legitimate
16 question.
17 COMMISSIONER SMITH: I think Mr. Kalich can
18 answer.
19 THE WITNESS: In this forum, when we're setting
20 up rules that are somewhat generic, we have to have a generic
21 type of a provision.
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There is some precedent in contracts before that
have been before this Commission, it's my understanding, on the
$45. Avista wants something there to ensure that when a QF
developer signs on the dotted line, that they actually perform,
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HEDRICK COURT REPORTING KALICH (X)
P. 0. BOX 578, BOISE, ID 83701 Avista
and we thought that the $45 would be reasonable.
Q. BY MR. RICHARDSON: Did you confer with anyone
from Idaho Power or Rocky Mountain Power when you came up with
this number?
A. I don't recall any discussions around that with
either of those Companies.
Q. On page 33 of your testimony, you note the risk
caused by recent FERC rulings on PURPA contracts constituting a
legally-enforceable obligation on the Utility. And you go on
to describe a, quote, legally enforceable obligation, unquote,
as the point when, quote, the Utility has tendered a contract
and the QF developer executes and returns the tendered
contract, obligating the Utility to purchase contract output.
Do you see that?
A. Yes.
Q. And don't -- and you've read the FERC rulings, I
assume, that you refer to?
A. Yes.
Q. And don't they actually say just the opposite,
and that is that a QF can unilaterally create a legally-
enforceable obligation on the part of the Utility to purchase
its output?
MR. ANDREA: I object: We don't have the Opinion
in front of us, and asking Mr. Kalich to recall a provision of
it without the Opinion is --
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HEDRICK COURT REPORTING KALICH (X)
P. 0. BOX 578, BOISE, ID 83701 Avista
COMMISSIONER SMITH: And, Mr. Richardson, I'd
note that I don't think Mr. Kalich is a lawyer, so if the
lawyers want to argue about what the FERC Order means, that's
fine, but he's given what he thinks it means and if it's
different from yours, then put it in your brief.
Q. BY MR. RICHARDSON: When you ask for liquidated
damages to be posted at the time the legally-enforceable
obligation arises, that's when you want it posted. Right?
A. The intent here was to ensure when the Utility
ends up with a legally-enforceable obligation, that there's
quid pro quo in the sense that the developer also has an
obligation to deliver to the Utility.
The discussion I had here and whether you want to
talk about it being at the legally-enforceable obligation or
simply when the contract is executed, I don't know that I have
a strong preference either way there. The point is, when the
contract is executed by the QF, it ought to come with a $45 per
kW deposit.
Q. And doesn't that place the QF in the position of
having to seek financing before it even has a Commission-
approved contract?
A. I don't think it necessarily would, no.
Q. So my $450,000, I'll just write a check?
A. There's a lot of predevelopment/preconstruction
costs that the developer incurs: Siting, permitting,
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HEDRICK COURT REPORTING KALICH (X)
P. 0. BOX 578, BOISE, ID 83701 Avista
et cetera. View this as a similar expense.
Q. So I just write a check?
A. That would be one way to do it, sure, post --
Q. And you have disagreed with Mr. Schoenbeck when
he made his mark to market proposal, in your rebuttal
testimony, page 13, stating that the mark to market method has
the potential to weaken developer performance incentives. Is
that correct?
A. Yes.
Q. Now, Mr. Schoenbeck suggests at page 44 of his
direct testimony that, quote: The QF could elect to post a
fixed dollar per kW amount or an amount based upon the
difference between the contract revenue payments and a
forward -- and forward power prices for a period of three years
starting at the expected commercial operation date.
And on page 13 of your rebuttal testimony, you
state that the mark to market method provides an inadequate
performance incentive.
My question is is it an inadequate mechanism for
Utility compensation for its costs due to the delay?
A. I think the reason we've talked about delay
security is the fact we really don't know in the future what
the actual damages will be. Therefore, in the example that
Mr. Schoenbeck put forth, it's very possible that market prices
could be low in the short run as they are today -- or, excuse
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HEDRICK COURT REPORTING KALICH (X)
P. 0. BOX 578, BOISE, ID 83701 Avista
that the QF developer actually perform.
Q. But a mark to market method of estimating damages
is actually an accurate way to identify the Utility's damages
for failure to perform. We're not talking about punishing the
QF, we're talking about making the Utility whole.
A. I would agree with that. The goal here isn't to
punish the QF at all, it's to prevent the Utility customers
from not being made whole.
So, three years is a fairly short period of time
pointed out earlier, to the extent the market prices happen to
be, for whatever reason, high -- we've seen some reasonable
volatility in the marketplace in the last few years -- you
actually could have a QF developer not have to post any
liquidated -- or, any damages security under Mr. Schoenbeck's
proposal, which I think would be a not very strong incentive
for a developer to perform on their contract.
Q. Well, couldn't you actually just sue a QF for
actual damages suffered who didn't perform?
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0 1 1 A. Many of these QFs don't have a balance sheet to
sue.
Q. How did Avista come up with the $45 figure?
A. I think I already answered that, and that was
based upon some information, previous contracts that we had
seen approved by the Commission. Further to that, we had done
some additional research that showed a range around $45 and
actually substantially higher in some cases. Again, it's based
on professional judgment, and again beginning with the
precedent of the Commission, we felt that 45 was a reasonable
number.
The goal here isn't so much the $45, it's to
ensure QF performance.
Q. So you did a survey of other Utilities, what they
were charging?
A. We actually had a consultant do a survey for us.
But, again, you can look at the public record
across the West Coast and you can see larger damage deposits as
well. Again, the $45 is something that's been used in Idaho,
and we thought it reasonable to ensure performance by the QF
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Q. At page 33 of your direct testimony, you state,
quote: In a period of falling prices, liquidated damages are
not assessed because market prices are lower than the contract
price.
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HEDRICK COURT REPORTING KALICH (X)
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2 A.
see that?
Q. Do you mean that the Utility has no damages in a
period of falling prices?
A. I'm not saying that. I think I'm just
emphasizing or pointing out the fact that it is possible --
again, we're looking in the future and there's no certainty.
We're looking out and saying it's possible that there could be
no damages specifically to that contract.
But the flip side is to the extent the market
moves the other direction, the Utility definitely is exposed.
Q. Do you believe that the liquidated damage
provision you are suggesting will have been agreed upon by a QF
when they signed that contract with you?
A. My testimony is hopeful the Commissioners will
decide in favor of this delay liquidated damages deposit is a
routine part of a standard QF contract or an IRP-based
contract.
Q. Do you think the QF has any bargaining power to
suggest that it could be something other than what you've
proposed?
MR. ANDREA: Objection: That calls for
speculation, beyond the scope again.
MR. RICHARDSON: I'll withdraw the question,
Madam Chair.
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Thank you, Madam Chair, for your indulgence.
Mr. Kalich, that's all I have.
COMMISSIONER SMITH: It appears that we're at a
good time for our morning break, and we'll return at 10:45.
(Recess.)
COMMISSIONER SMITH: Welcome back.
Mr. Uda, do you have questions?
MR. UDA: I just have a couple of follow-up
questions just to make sure that I understood the testimony.
There won't be very many, Madam Chair.
CROSS-EXAMINATION
BY MR. UDA:
Q. Mr. Kalich, I just want to make sure I understand
something. So, I'm not sure of the exhibit number, but it's
loads and resources exhibit. What was that?
COMMISSIONER SMITH: 510.
COMMISSIONER KJELLANDER: 511.
MR. UDA: 510. Is that correct?
COMMISSIONER SMITH: This one?
MR. UDA: Yes, that's the one.
Q. BY MR. UDA: And I noted on page 2 of that
exhibit, you had a discussion with Mr. Richardson about need
for winter 18-hour capacity loads and resources using
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P. 0. BOX 578, BOISE, ID 83701
Avis t a

1 essentially surplus power from the Northwest. Is that right?

2 A. The -- if you're asking, just to clarify, if this
3 L and R includes surplus regional power, yes.
LIM
Q. Right. And those are, as Mr. Richardson pointed

5 out, as I recall, not contracted-for resources. Those are not
6 resources you could automatically call upon. Is that correct?

7 A. The Power Council actually, as part of this

8 exercise, has identified resources that not only aren't
9 contracted for by Avista but don't have any long-term contracts

10 themselves --

11
Q. Right.

12 A. -- with any other party.

13 Q. Right. So, is it true that you are taking the

14 risk that these resources might not materialize?

15 A. These resources are already in the ground,
16 producing power today, so there really is no risk similar to a

17 new resource like a QF. There is no concern over whether that

18 resource will actually be economic- or -- economically not

19 justified or not being built due to some other circumstance.

20 So, they're generating power today, we expect them to generate

21 into the future.

22
Q. Right. But right now, you don't have a contract
23 with them that says that you can enforce that. Right?

24 A. Yeah, we don't have any contractual right, that's

25 1 true.

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Q. And during this forecast period --
Well, first of all, is it correct that this is,
in 2012, 600 megawatts of your resources, you're counting this
resource adequacy?
A. Yeah, I think it might be instructive to look at
page 2, which is -- and, again, this is just the winter load
and resource tabulation. We haven't yet talked about the
summer capacity or energy.
If you look at 2012, you can see even without the
resources we are essentially flat; in other words, we don't
have a deficiency.
The other thing I point out is that we have
pretty drastic -- we've recognized the risk inherent in relying
on a market surplus in the long run. In other words, we can
have regional load growth, we can have a coal plant shut down,
those kinds of things, which, by the way, expected shutdowns
like Boardman, the Council has already counted for.
So what Avista did in its resource plan to be
conservative is we reduced that surplus by ten percent a year,
so at the end of ten years we have no additional surplus in
there at all, again recognizing the fact over time we have less
certainty about how much surplus is out there in the
marketplace.
Q. And over that ten-year period of time that you're
counting the regional surplus, is it also correct that when
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1 you're entering into contracts with new QFs, they're going to

2
have to -- I can't remember what you called it -- delay

3 security deposit or whatever it is?

4 A. Yeah, the delay security deposit. In any QF

5 contract, we're asking the Commission to provide delay security

6 deposits.

7
Q. So you believe that, for example, a 500 kV QF

8 contract poses you such risk that you need to get this money
from them in whatever form, but at the same time, you're

10 willing to rely on a resource you don't have contracts with to

11 serve to meet your planning reserve margin?

12 A. One of the challenges that we face with PURPA

.
13
development and the PURPA law is we have to have substantially

14 a one-size--fits-all or in this case we're looking at maybe a

15 couple different methodologies, but we can't in a normal, as we
16 would in a normal competitive environment, develop a contract

17 that would be unique to whoever is supplying us power. We're

18 having to create a single -- more of a single, you know, a

19 provision to meet all contract requirements.

20
The differences, as I pointed out earlier, is
21 with a QF contract, we are looking towards new development

22 generally, and we're looking towards them not actually having a

23 resource online. Once the resource is online and providing
24 power into the region, then we can do assessments of how much

25 surplus we think might be able for Utility service in the
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1 future with or without a long-term contract.

2 MR. UDA: No further questions.

3 COMMISSIONER SMITH: Mr. Miller.
MR. MILLER: No questions, Madam Chairman.

5 For the purpose of assisting you, unless

6 something comes up, I don't anticipate questions for any

7 witness other than Idaho Power witness Park.

8 COMMISSIONER SMITH: Mr. Williams.

9 MR. R. WILLIAMS: No questions.

10 COMMISSIONER SMITH: And Mr. Arkoosh.

11 MR. ARKOOSH: I have a couple, and thank you,
12 Madam Chairman.
13

14 CROSS-EXAMINATION
15

16 BY MR. ARKOOSH:

17 Q. Mr. Kalich, I want to visit with you a little bit

18 about the terms you used in your direct testimony versus what

19 some of the things that were said here today. I was going to

20 see if that's all right with you, but I guess it is.

21 You talked in your testimony about put options,
22 and you said in your direct testimony the QF developer has a

23 free option.

24 You're not -- you're not contending that these
r 25 PURPA contracts are anything other than legally-enforceable
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obligations or contracts to perform, are you?
A. What I'm stating in my testimony, I stated today,
is these contracts, by their nature, absent liquidated damage
provisions, are essentially a free put option on the Utility.
Q. So a put option is an option to sell at an agreed
price at a specified future date. Isn't that correct?
A. Yes.
Q. And these contracts don't say, Mr. Developer,
Mr. QF, if you want to, you can sell at a price. They say you
are bound to deliver the output of your plant at a price.
Isn't that correct, you are contractually bound?
A. Exactly. The challenge here becomes when there
is really no recourse for the Utility. So to the extent if you
were a QF developer and signed a contract and had a balance
sheet that could actually support that development, there would
be recourse for the Utility. In many cases, maybe in most
cases, the QF developer doesn't have a balance sheet. So while
there's not an explicit put option stated contractually in the
document, it becomes one by the fact that the Utility has no
recourse in the event of nonperformance.
Q. Well, in fairness, it doesn't really become a put
option, it becomes a noncollectible breach, is your concern?
A. Categorize it how you will.
Q. Well, I do see a difference between a contract
and an option.
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2 good deal then, as you've described, the QF just may walk away

3 from it?

4 A. I didn't say anything about it being a good deal.
I just said the Utility would sell a contract obligating it to
6 purchase the QF power at a fixed priced.

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Q. If it was advantageous then, if it was -- if the

8 price was better in the future for the QF, you're worried it
9 will walk away from the deal?

10 A. At the time the contract is signed, basically,

11 it's a legal obligation of the Company. I have no ability,

12 really, to manage that contract except hope it arrives on the

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14 contract or one that's costly to my customers, the goal at the
15 time of contracting is to ensure performance by the QF.

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Q. Well, today, are you of the opinion that these

17 are nonbeneficial for the customer, today's contracts?

18 A. Well, I can say that the wholesale market price
19 at least the first seven months or six months of this year were

20 $13 a megawatt hour and the QF contract is multiples of that,

21 so if I had my druthers, I would have an opportunity to not
22 purchase the QF power, but by federal law I'm obligated to
23 purchase that power and certainly I'm not challenging federal

24 law here.

25 Q. So as a rational economic being, these QF5 are
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1 not going to walk away from these contracts, today anyway?
2 A. I don't think that's -- I don't think the
3 wholesale market is the whole piece of the equation here. I
think there's a lot of other things going on in the marketplace
beyond wholesale market prices that could affect a QF's ability
6 to perform.

7 Q. You expressed a second concern that you wouldn't,

8 as you expressed on page 31 of your testimony -- you said:
9 Once a PURPA contract is executed by the parties it becomes a

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firm contract in the Utility's resource stack and, as such, the
11 proposed QF resource postpones the development of other

12 alternative resources.
0 13 Do you recall that?
NXIM A. I'm at page 1. Is this my rebuttal or my direct?

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Q. Your direct, I believe.

16 A. Okay. Do you know what line that was?

17
Q. No, I didn't mark the line. Do you agree with

18 that statement?

19 A. Please, state it again. I was searching for it

20 as you were speaking.

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Q. Okay. Once a PURPA contract is executed by the

22 parties it becomes a firm contract in the Utility's resource

23 stack and, as such, the proposed QF resource postpones the

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development of other resource alternatives.

25 A. Yes.
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Q. Okay. But it's been pointed out twice now today
you testified that you do have other resource alternatives,
even noncontracted ones, which the Utility believes it's
prudent to include in its resource -- anticipated resource
stack?
A. Again, that's where we're at today. We won't
know what it will be multiple years into the future.
Q. But when we're there in multiple years in the
future, isn't there a -- isn't there a ascernible price or a
spot market where you can cover the loss of the nondelivered
energy?
A. Actually, I just will clarify my last statement:
There will be a supply, so the supply is less of a concern. It
really gets down to price, which is what you just asked.
Speaking from the Utility's perspective, the
concern is as market prices fluctuate, prices climb and rise,
and since we don't have a long-term contractual commitment with
these resources, we're going to pay the spot market price. So
if gas prices double, triple, quadruple -- I mean, we saw just
horrific gas prices in 2008 -- then the Utility, and by the
nature of how regulation works our customers, would have to pay
that higher price. So it's less •a concern about the resource
coming, it's more about price.
Q. Okay. And if Mid-Columbia trading, sometimes
that price is even negative, isn't it? You can be paid to take
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1 the power?

2 A. Yes.
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if there's a breach, we do know we have a spot market, and we
5 do know it may cost the Utility in order to place the energy or
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it may cost the Utility less to place the energy. Is that

7 correct?

8 A. That's correct.
9
Q. Okay. And the same goes for capacity: You have

10 an integrated resource plan, so if this piece of capacity goes

11 away, there's capacity to replace it that can be priced at the

12 time it needs to be replaced. Is that correct?
0 13 A. Yes.

14 Q. Okay. So it's a fair statement then to say that
15 although we don't know what the future actual damage will be

16 for breach, that damage is calculable at the time of the

17 breach?

18 A. I think, substantially, it could be calculated.

:19 The challenge would be, again, if it's a 20-year -- well,

20 actually, I have to retract that.

21 It's a 20-year contract, so we may know in the

22 short run what the damages could be. We would not know what

23 the 20-year damage could be.

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Q. Correct. But if we get to year 18, we could look
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A. Yeah, out in the future.
Q. Folks talked to you about the $45 per kilowatt.
At page 32, you said: There is precedent in recent Idaho PURPA
contracts for a $45 per kilowatt deposit based upon installed
capacity.
Do you recall that?
A. Yes.
Q. That is -- that is the only current calculation
of anticipated damages in this -- in your part of the record,
isn't it?
A. In this case?
Q. Yes, in this case.
A. This is the only number I have put out, yes.
Q. Okay. And it's based upon what people are doing
in other contracts. Is that what you mean by "precedent"?
A. Yes.
Q. Okay. It's not -- okay.
Mr. Kalich, at page 10 of your testimony, you
talked about Utility need being a factor in the price paid for
QF power. Do you recall that, sir?
A. Yes.
Q. Okay. And at line 8, if you want to follow along
here, I'm just going to read a sentence or two.
MR. ANDREA: I'm sorry, Mr. Arkoosh, could you
tell me which page you're on?
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MR. ARKOOSH: Yes. Page 10, line 8.
MR. ANDREA: Thank you.
THE WITNESS: Is this my direct testimony?
Q. BY MR. ARKOOSH: Yes. It says: When deficit --
do you see that language -- when deficit, avoided costs --
A. Yes.
Q. -- are those that would be paid for a least-cost
alternative resource or resources providing equivalent value.
When the Utility is in a surplus position, it will not avoid
any costs as a result of the QF purchase. At most, the actual
value of the QF purchase to the Utility is only the avoided
fuel cost at existing facilities. A more generous
interpretation of the PURPA obligation is to compensate a QF
developer during times of system surplus at the market price
received for the sale of energy net of delivery cost of the
market trading hub.
Is that your opinion today?
A. Yes.
Q. Okay. Is that what you meant at -- when you said
at page 5 and quoted from PURPA, you said that the rates for
such purchases shall be just and reasonable to the electric
consumer? Is that what you were talking about?
A. Sure, yes.
Q. Will you agree then that the "just and
reasonable" language was intended to require that the purchased
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rate be set at the lowest possible reasonable rate consistent
with the maintenance of adequate service in the public
interest?
A. That's a pretty loaded question. It gets back to
I think it needs to be set at Utility avoided cost.
Q. Well, is that the lowest possible reasonable rate
consistent with the maintenance of adequate service in the
public interest?
A. I'm not aware of where that statement came from.
That's not how I would word it.
Q. Do you agree or disagree, or don't know?
A. I think I would again point you back to the
principles of avoided cost which are adopted in my testimony.
Q. Okay.
MR. ARKOOSH: I have nothing further, Madam
Chairman. Thank you very much.
COMMISSIONER SMITH: Ms. Sasser, did I give you a
turn?
MS. SASSER: You have not. Is it my turn? Thank
you, Madam Chair.
CROSS-EXAMINATION
I just have one question, Mr. Kalich, for
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1 purposes of clarification:
2 On page 17 in your rebuttal testimony, you
3 generally speak to Dr. Reading's direct and references to
4 Avista's Reardan plant?
A. Yes.
Q. What Reardan costs, if any, have been included in
Avista's rates?
A. To my understanding, there's been no costs of
Reardan in Idaho rates.
MS. SASSER: That's my only question. Thank you.
COMMISSIONER SMITH: Do we have questions from
the Commissioners?
COMMISSIONER REDFORD: None.
COMMISSIONER KJELLANDER: Just one.
COMMISSIONER SMITH: Commissioner Kjellander.
EXAMINATION
BY COMMISSIONER KJELLANDER:
Q. Mr. Kalich, in your understanding of the dealings
of the Commission in the past as it may relate to delay
securities, would it be reasonable to say that you have seen
opportunities in which the developer and the Utility have been
able to renegotiate how much of that security actually is paid
when a project defaults?
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A. Yes, I think I've seen that.
Q. Thank you.
COMMISSIONER SMITH: Do you have redirect,
Mr. Andrea?
MR. ANDREA: I think I have one or two questions
if I could just have a moment, please.
I think I'll try and keep it to just one.
REDIRECT EXAMINATION
BY MR. ANDREA:
Q. In Exhibit 510 that Mr. Richardson offered,
there's been quite a bit made of this chart on page 2 and the
use of surplus in your planning. Would it be prudent to not
consider that surplus in your planning?
A. We think it's absolutely essential. The
Northwest has a significant overbuild of assets today that are
"trapped," for lack of a better term, in the Northwest, and
they're available. By building new resources today is much
more expensive than purchasing asset that's already in the
ground.
Q. I apologize, I'm going to break the rule of doing
another question when I said I was only going to do one.
At the time when you enter into contracts with
QF5, do you have any way of knowing what the price of energy
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will be two years, five years, into the future?
A. There are indications in the marketplace for
forward contracts, et cetera, but we have no certainty.
Q. So there's no way to know what your actual
damages are going to be if the QF does not come online as
committed?
A. That's correct.
MR. ANDREA: Thank you.
COMMISSIONER SMITH: Thank you, Mr. Kalich.
(The witness left the stand.)
COMMISSIONER SMITH: Is that all of your
witnesses?
MR. ANDREA: Yeah, Madam Chair, we have nothing
further.
COMMISSIONER SMITH: I think we're ready now to
go to Mr. Solander.
MR. SOLANDER: Thank you, Madam Chair. Rocky
Mountain Power calls Brian Dickman.
COMMISSIONER SMITH: And did Mr. Kalich need to
be excused or is he here for the duration?
MR. ANDREA: Madam Chair, I'd ask that he be
excused. I believe he'll be here for tomorrow, but I don't
think he'll be here Thursday.
COMMISSIONER SMITH: If there's no objection, we
will excuse Mr. Kalich.
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1 BRIAN DICKMAN,
2 produced as a witness at the instance of Rocky Mountain Power,

3 being first duly sworn, was examined and testified as follows:
4

5 DIRECT EXAMINATION
6

7 BY MR. SOLANDER:

8
Q. Good morning, Mr. Dickman.

9 A. Good morning.

10
Q. Would you please state your name for the record?

11 A. Brian Dickman, D-I-C-K-M-A-N.

12
Q. And by whom are you employed and in what

.
13 capacity?

14 A. I'm employed by PacifiCorp as the manager of net

15 power costs.

16
Q. And in this proceeding, are you adopting the

17 direct testimony of Kelcey Brown and Exhibit 201 thereto as

18 part of this proceeding?

19 A. Yes.

20
Q. And did you also file rebuttal testimony in this
21 proceeding?

22 A. I did.

23
Q. And do you have any corrections to either

24 Ms. Brown's or your rebuttal testimony?
.
25 A. I would like to make a correction to my rebuttal
HEDRICK COURT REPORTING DICKMAN (Di)
P. 0. BOX 578, BOISE, ID 83701 Rocky Mountain Power
1 testimony. On page 6, Table 1 --

2 Q. Give everybody a moment so they can go there.
3 A. A small correction is required to the table. The

4 avoided cost rate in dollars per megawatt hour under the
January 2012 heading should read 33.17, and the avoided cost
6 rate under the May 2011 heading should be 53.29. And,

7 consequently, the 20-year ratepayer cost under the January 2012

8 heading would be 44.16 million, and the 20-year ratepayer cost
9 under the May 2011 heading would be 70.96 million. And

10 notwithstanding those corrections, the delta of 26.8 million

11 would be.

12 Q. Does that conclude the corrections you have for
.
13 your testimony?

14 A. Yes.

15 MR. SOLANDER: I would ask that the direct
16 testimony of Kelcey Brown and the rebuttal testimony of Brian

17 Dickman, and Exhibit 201 to Ms. Brown's testimony, be spread

18 upon the record as if read.

19 COMMISSIONER SMITH: If there -- is there any

20 objection? Seeing no objection, we will spread the prefiled

21 testimony of Ms. Brown and the rebuttal testimony of
22 Mr. Dickman upon the record as if read, and admit Exhibit 201.

23 (The following prefiled direct testimony

24 of Ms. Brown and the prefiled rebuttal testimony of Mr. Dickman

25 are spread upon the record.)
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1 Q. Please state your name, business address and present position with
2 PacifiCorp, dba Rocky Mountain Power Company (the "Company").
3 A. My name is Kelcey Brown and my business address is 825 NE Multnomah Street,
4 Suite 600, Portland, Oregon 97232, and my present title is Lead/Senior
5 Regulatory Consultant.
6 Qualifications
7 Q. Briefly describe your education and business experience.
8 A. I have been employed by PacifiCorp since May 2011. Since that time I have
9 worked on net power costs, avoided cost proceedings, and the preparation of the
10 Company's Federal Energy Regulatory Commission ("FERC") transmission rate
11 case filing. Prior to joining PacifiCorp, I worked at the Oregon Public Utility • 12 Commission from November 2007 through May 2011. During my time at the
13 Commission I sponsored testimony in several dockets involving net power costs,
14 integrated resource planning, and various revenue and policy issues. From 2003
15 through 2007 I worked as the Economic Analyst for a telecommunications
16 company, Blackfoot Telephone, where I was responsible for revenue forecasts,
17 resource acquisition analysis, pricing, and regulatory support. I have a B.S. in
18 Business Economics from the University of Wyoming, which I received in 2001,
19 and completed all course work towards a Master's degree in Economics from the
20 University of Wyoming, which focused primarily on regulatory economics.
21 Summary of Testimony
22 Q. What is the purpose of your testimony?
23 A. The purpose of my testimony is to provide information regarding the
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1 appropriateness of the Commission approved methodologies to calculate avoided

2 costs rates for Idaho qualifying facilities ("QF"). More specifically, I will discuss

3 the Surrogate Avoidable Resource ("SAR") methodology to calculate published

4 rates and the Integrated Resource Plan ("IRP") methodology to calculate

5 negotiated contract rates.

6 Q. Is the Company presenting any additional witnesses in this proceeding?

7 A. Yes. Mr. Paul H. Clements, an originator for PacifiCorp Energy, presents

8 testimony describing the Company's experience under the current avoided cost

9 methodology for QF customers that do not qualify for published rates. In addition,

10 he sponsors a proposed tariff Schedule 38 which is intended to govern the QF

11 process when a developer requests pricing of Non-Standard QF contracts in Idaho

S 12 going forward. Lastly, Mr. Clements will provide comments on the ownership of

13 renewable energy credits ("REC") as it pertains to QFs.
14 Background

15 Q. Why is the Company reviewing the SAR and IRP based methodologies?

16 A. On August 6, 2009, the Idaho Public Utilities Commission (Commission) opened

17 a generic docket (Case No. GNR-E-09-03) to assess the continued viability of the

18 Commission's existing proxy unit or SAR methodology for calculating published

19 avoided cost rates. Specifically, the Commission wanted to explore the continued

20 reasonableness of using published avoided cost rates as presently calculated for

21 all Qualifying Cogeneration and Small Power Production Facility ("QF") resource

22 types.

23 The Commission directed that the appropriateness of a single avoided cost
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SAR methodology for published rates was to be re-examined in the context of
PURPA and FERC requirements and how different generation and operation
capabilities compare with other resources being offered to Idaho utilities. Under
the Commission's direction, Staff prepared a straw man wind SAR proposal
which was distributed to interested parties ("QFs and utilities") on May 27, 2010,
for their review and comment.
On June 18, 2010, interested parties filed reply comments. A workshop
was held November 3, 2010, to discuss the straw man proposal and the parties
reply comments. On November 5, 2010, Idaho Power, Avista, and Rocky
Mountain Power filed a joint petition requesting that the issues raised in the
workshop be addressed and that the eligibility cap for published avoided cost rates
be lowered to 100 W.
On December 3, 2010, the Commission issued Order No. 32131 directing
Avista, Idaho Power, Rocky Mountain Power and other interested parties to
address the utilities' petition to reduce the published avoided cost eligibility cap.
Comments and reply comments were filed and oral arguments were held January
27, 2011. On February 7, 2011, the Commission issued final Order No. 32176
temporarily reducing the eligibility cap to 100 kW for published avoided costs
rates.
On June 8, 2011, the Commission initiated Case No. GNR-E-1 1-01 (Phase
II) to investigate and determine requirements by which wind and solar qualifying
facilities ("QFs") could obtain a published avoided cost rate without allowing
large QFs to obtain a rate that does not accurately reflect a utility's avoided cost
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0 1 for such projects. Specifically, the Commission solicited information and

2 investigation of a published avoided cost rate eligibility cap structure that: (1)

3 allowed small wind and solar QFs to avail themselves of published rates for

4 projects producing 10 aMW or less; and (2) prevents large wind and solar QFs

5 from disaggregatmg into small projects in order to obtain published avoided cost

6 rates that exceed a utility's actual avoided cost.

7 Case No GNR-E-1 1-01 affirmed the Commission's decision to maintain

8 the 100 kW eligibility cap for published avoided cost rates for wind and solar

9 QFs, and stated its intent to initiate a proceeding to investigate and analyze both

10 the SAR and IRP methodologies. In its Notice of Review, in Order No. 32352,

11 dated September 1, 2011, the Commission initiated this proceeding to reexamine

S 12 the appropriateness of both the SAR and IRP methodologies for calculating

13 avoided cost rates.

14 Q. Please summarize your testimony.

15 A. The Company's position is that the current implementations of the SAR and IRP

16 methodologies are appropriate for the published and negotiated avoided cost rates,

17 respectively, as long as the 100 kW eligibility cap threshold for wind and solar

18 QFs is maintained for published SAR rates. The SAR methodology used for

19 calculating published avoided cost rates for smaller QFs continues to provide a

20 simple and transparent means of pricing that minimizes transaction costs a very

21 small QF might incur to negotiate a power purchase agreement. However, the

22 SAR methodology is not the best methodology as the QF project capacity

23 increases since it does not take into consideration the value a specific QF project
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1 would provide to each utility's unique power system and does not account for the
2 characteristics of each individual QF. The IRP methodology on the other hand, as
3 established in IPC-E-95-09, is an appropriate method to assess the value of a QF
4 project in terms of its capability to deliver its resource when the Company is in
5 need of such a resource, and is reflective of the value of the QF to the Company
6 and its customers Table A, provided below, is a summary of the IRP avoided cost
7 rates for a representative QF of each technology type.
Table A'
RMP-IRP Calculation Method for Avoided Cost Rates
Molded Cost: 20-Year Nominal Lewlized
Project Capacity Capacity Capacity Energy Capacity Fst. $IMWHat
Description (MW) Factor Contribution ($/MWh) ($IkW-yr) Stated CF
Base Load Thermal 20 92.0% 100.0% $40.57 $118.16 $55.23
Hydro 20 34.0% 64.6% $46.96 $76.80 $72.75
Solar (Peak) 20 22.6% 26.8% $3999* $31.67 $55.99
Solar (Energy) 20 22.6% 13.6% $39.77* $16.07 $47.89
Wind 22 34.4% 4.2% $31.52* $4.96 $33.17
* Avoided energy cost reduced for renewable integration charge at $6.50 ($2009).
8 The SAR Methodology
9 Q. Please provide an overview and history of the SAR methodology in
10 calculating published rates for Idaho QFs.
11 A. The SAR method uses the fixed and variable cost of a combined cycle
12 combustion turbine ("CCCT") as a proxy resource and assumes that these costs
1 The Solar (Energy) and Solar (Peak) projects are representative of a solar project that is configured to
. produce the maximum amount of total energy versus ,a solar project that is configured to produce more
energy during the Company's system peak.
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1 represent the utility's long term avoided costs.2 The Commission originally

2 established the SAR method over 30 years ago on August 8, 1980, when the

3 Commission issued its first order, Order No. 15746, establishing the principles

4 applicable to purchases of power from PURPA QFs.3 In Order No. 15746, the

5 Commission determined that a hypothetical base load coal plant would be the unit

6 a utility would build or defer absent QF generation and was representative of the

7 utility's avoided cost.

8 In 1993, in Case No. PPL-E-93-5, the Commission concluded that the

9 SAR proxy resource should be a CCCT rather than a coal plant.4 Since then, there

10 have been periodic updates of the underlying CCCT costs, but the SAR method

11 itself has changed very little.

. 12 Q. Is the Company proposing any changes to the SAR method of calculating

13 published avoided cost rates?

14 A. No.

15 Q. Do you believe that the SAR method is an appropriate methodology to value

16 the energy and capacity that small QF resources provide to utilities?

17 A. Yes. With the recently affirmed 100 kW eligibility cap for wind and solar QFs,

18 the SAR method is a reasonable methodology for calculating published avoided

19 cost rates for resources that will not materially impact a utility's load and resource

20 plan.
2 Case No. U-1500-170, Order 22636 I.P.U.C. 6-7 (1989).
See Case No. P-300-12, Order 15743 I.P.U.0 31(1980), Order 16025 I.P.U.0 31(1980). 4 See Case No. PPL-E-93-5, Order 25882 I.P.U.C. 3-4. See also Case Nos. WWP-93-10, IPC-E-93-28 PPL-
. E-93-5, and UPL-E-93-7 where the utilities filed simultaneous applications representing that the SAR
methodology based on a coal resource was no longer fair, just, and reasonable.
Brown, Di - 6
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1 Q. Does the Company believe it is important to maintain the recently affirmed

2 size eligibility thresholds for wind and solar QFs seeking Idaho published

3 avoided cost prices at 100 kW?

4 A. Yes. As discussed by Company witness Mr. Bruce Griswold in Case Nos. GNR-

5 E-10-04 and GNR-E-11-01, the Company believes the 100 kW eligibility cap for

6 wind and solar QFs and the use of an IRP methodology as explained below for

7 larger projects is appropriate, does not deter wind or solar development, and is the

8 surest reasonable approach for restricting disaggregation.
9 The IRP Methodology

10 Q. Please provide a background of the IRP methodology

11 A. On January 31, 1995, the Commission issued Order No. 25882, requiring the

. 12 Company to develop an IRP-based methodology to calculate avoided costs for QF

13 resources exceeding the then one megawatt ("MW") eligibility cap. In its order,

14 the Commission stressed that the methodology should price QF resources such

15 that customers would be indifferent to whether capacity was procured as a result

16 of the IRP process or as a result of a QF contract. The Commission noted that:

17 "Requiring [QF] projects to prove their viability by market standards

18 ensures that utilities will not be required to acquire resources priced higher

19 than would result from a least cost planning process."5

20 Parties then stipulated to Staff's proposed IRP methodology in Case No. IPC-E-

21 95-09 and the stipulation was subsequently adopted by the Commission in Order

22 No. 26576.

23 Q. Please describe the IRP methodology.

24 A. The IRP methodology is comprised of seven steps, which essentially values the
Case No. PPL-E-93-5, Order 25882 I.P.U.C. 7. 90
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I

1 avoided cost Of the QF by taking the difference between the present value revenue

2 requirement ("PVRR") of the base case resource plan and a modified resource

3 plan that includes the QF resource. These seven steps, as established in the

4 stipulation adopted in Case No. IPC-E-95-05, are as follows:

5 1. An IRP is prepared for the Utility. The IRP should consider a range of

6 load forecasts for various sets of possible economic conditions. The

7 IRP should also consider all possible resources for meeting load, both

8 supply side and demand side. In addition, consideration should be

9 given to the risks and uncertainties associated with each scenario

10 examined. The least cost combination of resources is selected to meet

11 each scenario. The most likely scenario is identified as the base case

12 plan.

13 2. An initial simulation analysis using a power supply and/or capacity

14 expansion model chosen by the utility is used to calculate the PVRR of

15 the base case resource plan over the lifetime of the proposed QF

16 contract.

•
17 3. The proposed QF resource is added to the base case resource plan

18 during all years of the proposed contract. The required description of

19 the QF project includes all data and information needed to model the

20 intended dispatchable or non-dispatchable operations of the project on

21 the power supply system (see pps. 9-10 for a list of data and

22 information needed from QFs).

23 4. A second simulation analysis, including the QF resource, is performed
24 which results in an adjustment of the amount and/or timing of the new

25 resources in the base case plan. The modified plan including the QF

26 purchase is constructed to maintain resource adequacy and system

27 reliability equivalent to that of the base case plan.

28 5. The PVRR of the modified resource plan including the QF is

29 calculated over the full term of the QF contract, excluding the total

30 purchase costs of the QF resource itself.

31 6. Finally, the present value of the QF project avoided cost is calculated
32 by subtracting the PVRR of the modified plan, with the costs of the QF

33 set to zero, from the PVRR of the base case resource plan.
34 7. Rates for capacity and energy from the QF project can now be

35 developed for which, on a present value basis, the expected payments
36 of the QF are equal to the project's avoided cost over the life of the
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1 contract.6
2 Q. Is the Company proposing any changes to the seven step IRP methodology
3 developed in IPC-E-95-09?
4 A. No. The IRP methodology continues to reflect an accurate forecast of the
5 Company's avoided costs Also, as a gauge of reasonableness and consistency, the
6 IRP methodology is similar to the non-standard large QF avoided cost
7 methodologies adopted by both of RMP' s other jurisdictions, Utah and Wyoming.
8 Q. What are the main components of the avoided cost price calculation using the
9 IRP methodology?
10 A. Using the IRP methodology, QF avoided cost prices consists of three components:
11 avoided energy costs, avoided capacity costs, and integration costs (where
. 12 appropriate).
13 Q. Please describe how the Company calculates the avoided costs of energy
14 under the IRP methodology.
15 A. The calculation of the avoided energy Cost follows the steps identified above and
16 begins with the existing and planned resources that represent the Company's IRP
17 preferred portfolio. Using the preferred portfolio, the Company runs two energy
18 simulations using its Generation and Regulation Initiatives Decision Tool
19 ("GRID") model. The first simulation (the Base Simulation) calculates the PVRR
20 of the preferred portfolio. The second simulation (the Avoided Cost Simulation)
21 calculates the PVRR of a modified version of the preferred portfolio that includes
22 the QF at no cost and includes the energy impact associated with the deferral of a
. 6 See Case No. IPC-E-95-9, Order 26576, I.P.U.C. (1996) approving the settlement stipulation set forth in
Staff Exhibit No. 101.
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1 portion of the next avoidable CCCT in a manner that maintains resource adequacy
2 and system reliability equivalent to that of the Base Simulation The difference in
3 PVRR from the GRID studies between the Avoided Cost Simulation and the Base
4 Simulation is used to determine the avoided energy cost. The avoided energy cost
5 does not include the benefit of deferring the fixed costs of the next avoidable
6 CCCT
7 Q. Please describe how the Company calculates the avoided costs of capacity
8 under the IRP methodology.
9 A The Company calculates the avoided cost of capacity outside of the GRID model
10 by determining the PVRR of the deferred fixed costs associated with the partial
11 displacement of the next deferrable CCCT in the Company's IRP. The levelized • 12 fixed costs of the deferrable CCCT, plus ongoing operation and maintenance, are
13 developed from the PVRR savings of the deferred fixed costs on a $IkW/year
14 basis Based on the estimated capacity contribution of the QF, the capacity
15 component is calculated and added to the energy component of the avoided cost
16 payment The attached Technical Appendix, Exhibit No 201, provides examples
17 and details how the Company uses its assumptions from the most recently filed
18 IRP for calculating the capacity payment portion of the QF avoided costs.
19 Different types of resources will have different abilities to defer the
20 capacity of the next deferrable CCCT. The Company refers to this as a resources
21 capacity contribution which I will discuss later.
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1 Q. How does the Company determine the "next deferrable CCCT" for purposes
2 of calculating the capacity payment?
3 A. A CCCI resource is deferrable or avoidable until the Company makes an
4 irreversible commitment to acquire it An irreversible contract commitment
5 generally occurs upon order approval of an acquisition of a resource, the
6 completion of an RFP process to build the resource or the execution of a contract
7 to procure the capacity. Currently, the next deferrable CCCT is the 597 MW type
8 "F" natural gas resource planned in the Utah South transmission area beginning
9 June, 2016
10 Q. What is capacity contribution?
11 A. Capacity contribution is the ability of the QF resource to contribute towards
. 12 meeting the Company's hourly summer peak system obligation to serve load For
13 non-intermittent thermal QF resources, such as cogeneration or biomass
14 resources, the Company assumes the QF' s entire rated capacity can contribute
15 towards the Company's summer peak obligation For intermittent resources, such
16 as wind and solar, and energy-limited resources, such as hydro, the Company
17 takes historical data from existing projects that have contributed to the
18 Company's summer peak obligation to determine the capacity contribution.
19 Q. How is the capacity contribution calculated for wind, solar and hydro QFs?
20 A. The Company matches the hourly generation profile for each of these
21 technologies against historical hourly loads from 2007 through 2010 and
22 identifies the quantity of generation of each technology during the Company's top
23 100 summer peak hours in each year. Next, the Company identified the amount of
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1 capacity contribution each technology would be expected to provide at least 90

2 percent of the time. This percentage was then used to establish the capacity

3 contribution for hydro, wind and solar QFs.
4 Q. Please summarize the Company's calculated capacity contribution of the

5 representative solar, hydro, wind and thermal QF resources.
6 A. The Company calculated a capacity contribution of its rated capacity of 4.2

7 percent for a wind resource, 64.6 percent for a hydro resource, 100 percent for a

8 thermal resource, and based on the configuration of the solar facility, 13.6 percent

9 for a solar facility that maximizes its energy across all hours, and a 26.8 percent

10 capacity contribution for a solar facility that is physically configured to produce

11 greater energy during the company's peak times, but with slightly less total
• 12 energy generation. For details of how the Company calculated the capacity

13 contributions for each resource please refer to Exhibit No. 201, which describes
14 and illustrates the assumptions and calculations used by the Company.

15 Q. Does the Company apply an integration charge to intermittent resources

16 such as wind and solar?

17 A. Yes. Pursuant to Order No. 31021 in Case No. PAC-E-09-07, the Company

18 applies a $6.5 OIMWH charge to wind and has also applied the same integration
19 charge to solar QFs.7 The integration charge represents a reduction to prices
20 provided to QF and is calculated on a nominal basis using real 2009 dollars.
The Company does not currently own or operate a solar facility. However, solar resources are intermittent
variable resources that present operational integration costs that are similar to that of a wind resource. The
.

Company believes that the wind integration charge, established by the Commission in Order No. 31021, is
a reasonable approximation of the integration costs associated with a solar resource.
Brown, Di - 12
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1 Q. Do previously signed QFs also impact the deferrable capacity available from
2 the next deferrable CCCT?
3 A. Yes. To the extent that the preferred portfolio, or deferrable CCCT, was modified
4 to take into consideration a signed QF, this partially displaced portion can no
5 longer be deferred. This ensures that the Company includes a consistent level of
6 capacity in the simulated resource portfolios as newly signed QFs are added into
7 the resource plan.
8 Q. At the time the QF makes a request for avoided cost prices, does the
9 Company update the GRID model for known and measurable changes that
10 occur subsequent to filing the IRP?
11 A. Yes. The Company updates the GRID model based on the most recently available
12 information each time a QF requests avoided cost pricing. This includes updates
13 related to new contracts, fuel prices, forward price curves, load forecasts and
14 other assumptions. However, the underlying IRP preferred portfolio does not
15 change and is consistent with the most recently filedTRP.
16 Q. Please summarize your testimony.
17 A. With the eligibility cap of 100 kW in place for solar and wind QF facilities, the
18 Company believes that the previously adopted SAR and IRP methodologies
19 continue to provide an accurate means of calculating avoided cost prices for Idaho
20 QFs.
21 Q. Does this conclude your direct testimony?
22 A. Yes.
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I

1 Q. Please state your name, business address and present position with

2 PacifiCorp, dba Rocky Mountain Power Company (the "Company").

3 A. My name is Brian S. Dickman, my business address is 825 NE Multnomah St.,

4 Suite 600, Portland, Oregon 97232, and my present title is Manager, Net Power

5 Costs.

6 Q. Have you previously sponsored testimony in this proceeding?

7 A. No. I am adopting the direct testimony of Company witness Ms. Kelcey Brown

8 that was submitted as part of the Company's original filing in this proceeding. I

9 am the Company witness responding to issues raised by intervening parties

10 concerning the Company's avoided cost methodology, including any issues

11 concerning the direct testimony and exhibits submitted by Ms. Brown.
S 12 Qualifications

13 Q. Briefly describe your education and business experience.

14 A. I received a Master of Business Administration from the University of Utah with

15 an emphasis in finance and a Bachelor of Science degree in accounting from Utah

16 State University. Prior to joining the Company, I was employed as an analyst for

17 Duke Energy Trading and Marketing. I have been employed by the Company

18 since 2003 including positions in revenue requirement and regulatory affairs, and

19 I assumed my current role managing the Company's net power cost group in

20 March 2012.

21 Q. Have you testified in previous regulatory proceedings?

22 A. Yes. I have filed testimony in proceedings before the Idaho Public Utilities

23 Commission, the Wyoming Public Service Commission, and the Utah Public
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1 Service Commission.
2 Testimony Summary

3 Q. Please provide an overview of your testimony.

4 A. My testimony responds to avoided cost modeling issues raised by the Idaho

5 Public Utilities Commission Staff ("Staff') and intervening parties in this

6 proceeding. Commercial avoided cost issues will be addressed in the testimony of

7 Company witness Mr. Paul H. Clements. In general, PacifiCorp agrees with Staff

8 witnesses Mr. Rick Sterling and Dr. Cathleen McHugh that the Surrogate

9 Avoided Resources ("SAR") and Integrated Resource Plan ("IRP")

10 methodologies are conceptually appropriate techniques to calculate avoided costs.

11 It is critical, however, that the IRP methodology reflects the best available

. 12 information to compute the avoided cost specific to each utilities system in order

13 to ensure Idaho retail customers remain indifferent whether the utilities procure

14 energy from qualifying facilities ("QFs") or through the pursuit of a least cost

15 plan developed in an IRP.

16 Q. How is your testimony structured?

17 A. My testimony addresses the following issues:

18 • IRP Methodology Updates - PacifiCorp recommends modeling inputs be

19 updated contemporaneously at the time of each pricing request in order to

20 minimize the cost to retail customers from using outdated modeling

21 assumptions.
.

•:
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1 • Choice of Model - The proposal that the Company be restricted from
2 using the Generation and Resource Integrated Decisions ("GRID") model
3 should be rejected.
4 • Timing of Capacity Payments - The Company's IRP process accounts for
5 the incremental need and cost of capacity on its system, and accordingly,
6 capacity payments should be determined based on the timing of the next
7 deferrable resource in the IRP preferred portfolio.
8 IRP Methodology Updates
9 Q. Please identify the issues raised regarding modeling updates in the IRP
10 methodology.
11 A. The two primary questions raised by parties are: 1) which avoided cost modeling
12 inputs should be updated between IRPs, and 2) how frequently should utilities
13 perform these updates. Modeling inputs are the key drivers for the price that is
14 offered to a QF using the IRP methodology and it is critical to use the best
15 available information.
16 Q. What updates did Staff recommend as appropriate to be made between
17 IRPs?
18 A. Staff witness Mr. Sterling proposes updates be made for fuel price forecasts, load
19 forecasts, and new long-term contract obligations (including new signed QF
20 contracts).
21 Q. Do you agree?
22 A. Yes. I agree that each of these inputs should be subject to update between IRPs,
23 with some clarification. For PacifiCorp in particular, in order to maintain
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0 1 consistency within the GRID model used for the IRP methodology, updating the
2 cost of fuel also requires updating forecast market prices for electricity. In
3 addition to Mr. Sterling's recommendation, PacifiCorp believes updates to all
4 executed purchase and sale agreements for power, fuel, transportation and
5 transmission (including short term agreements) are necessary to achieve a
6 matching of the best available information at the time of the pricing request.'
7 PacifiCorp also agrees with Mr. Sterling's recommendation that updates to fuel
8 and electricity price forecasts should be from the same sources (or combination of
9 sources) as used in the Company's IRP.
10 Q. Did others make recommendations regarding which updates should be
11 allowed?
• 12 A. Yes. Mr. Don Schoenbeck recommended only updating natural gas prices from a
13 third party source and executed QF purchase power agreements. Dr. Don Reading
14 proposed that only natural gas prices from a third party source be updated.
15 Q. Do you agree with these recommendations?
16 A. No. These proposals limit the Company's ability to accurately calculate avoided
17 costs. Updating the natural gas price in isolation is appropriate for the SAR
18 methodology since the SAR model only considers the overall cost of a Combined
19 Cycle Combustion Turbine ("CCCT"). On the other hand, the IRP methodology
20 relies on the overall value a QF would provide when added to the Company's
21 resource portfolio. To accurately calculate that value requires the use of a
22 production cost model such as GRID updated with the most current information
'Contrary to Dr. Reading's statement on page 25 of his direct testimony, to avoid skewing the calculation
. of avoided costs, modeling updates are made to both the base case and the incremental case that includes
the zero-cost QF resource.
200 Dickman, Re -4
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0 1 available. Updating natural gas prices in isolation could produce unintended

2 results. As mentioned above, the GRID model requires an update to the forward
3 market prices for electricity coincident with changes in natural gas prices.

4 Increasing natural gas prices without increasing wholesale power market prices,

5 as some have proposed, could result in natural gas-fired resources not generating

6 due to the inaccurate spark-spread. This does not reflect reality since wholesale

7 power market prices would likely increase in parallel with increases in natural gas

8 prices allowing natural gas-fired resources to continue to operate economically.

9 Q. What recommendations were made regarding the frequency of modeling

10 updates?

11 A. Mr. Sterling recommends annual updates for load and fuel forecasts, while

• 12 updates for new contracts would be done whenever a new long-term purchase or
13 sale commitments is made. Mr. Schoenbeck and Dr. Reading each propose to

14 limit updates to once per year.

15 Q. Do you agree?

16 A. No. PacifiCorp recommends updating all modeling inputs, other than the

17 incremental resource additions outlined in the IRP preferred portfolio, at the time

18 the QF pricing is prepared. This will ensure that the IRP methodology provides

19 the most accurate avoided costs and will maintain retail customer indifference.

20 These types of updates are routinely made for the Company's avoided cost
21 calculations in Utah and Wyoming.
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0 1 Q. Have you calculated an example of the effect using outdated modeling inputs
.
2 can have on avoided cost prices?
3 A. Yes. Table 1 below provides two calculations of avoided cost rates for the
4 hypothetical 22 megawatt ("MW") wind resource included in Table A of Ms.
5 Brown's direct testimony, which I have adopted. The illustrative wind avoided
6 cost price in Ms. Brown's direct testimony was based on modeling inputs current
7 as of January 2012. Alternatively, I have calculated the avoided cost for the same
8 wind resource using modeling inputs current as of May 2011, eight months
9 earlier.
Table 1
Impact of Using Outdated Modeling Inputs
Idaho Wind: 22 MW 34.4% CF
Model Updates Through
January 2012 May 2011 Delta
Avoided Cost Rate ($/MWH) (a) $33.09 (b) $53.22 (c) $20.13
Annual Generation (MWH) 66,576 66,576 -
Annual Ratepayer Cost $2,202,784 $3,542,843 $ 1,340,059
20 Yr. Ratepayer Cost $ 44,055,679 $ 70,856,856 $26,801,177
10
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12
13
14
15
•16
(a)Nominal Levelized 2013 - 2032
(b)IRP Methodology avoided cost from the direct testimony of Ms. Browi.
(c)Recalculated avoided cost using model inputs dated May 2011
As shown in the first column of Table 1, using more recent modeling inputs
resulted in annual avoided cost payments of $2.2 million or $44.0 million over a
20 year contract term. Using model inputs from only eight months earlier would
have result in annual avoided cost payments of $3.5 million or $70.9 million over
a 20 year contract term. If the Company did not have the ability to base pricing on
the most accurate information known to the utility at the time of the request, $26.8
million of additional cost would be imposed on retail customers over the life of
202 Dickman, Re - 6
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1 the contract.
2 Q. Does the impact of using outdated inputs have the potential to exceed $26.8
3 million?
4 A. Yes. Had the same pricing been provided to an 80 MW wind facility, the impact
5 of using outdated modeling inputs would exceed $97 million 2 over a 20 year
6 contract term.
7 Q. What arguments are made to justify less frequent updates to modeling
8 inputs?
9 A. Parties have presented three general arguments to justify the use of non-
10 contemporaneous modeling inputs. The first argument, made by witnesses Dr.
11 Reading and Mr. Schoenbeck, is that performing due diligence on
. 12 contemporaneous model inputs imposes an undue burden on QF developers. The
13 second argument, made by Mr. Sterling, is that the use of contemporaneous model
14 inputs would complicate contract negotiations. The third argument, made by Mr.
15 Schoenbeck, is that the use of contemporaneous data enables utilities to
16 manipulate prices.
17 Q. Are these arguments persuasive?
18 A. No. The merits of these arguments must be weighed against the tens of millions of
19 dollars of needless cost that limiting updates to an annual cycle could impose on
20 retail customers. As demonstrated in Table 1 even a relatively small QF contract
21 commits customers to significant costs over the life of the QF obligation.
is
2 $26.8 million * 80 MW /22 MW.
Dickman, Re - 7
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1 Q. How do you respond to the argument that the use of contemporary inputs
2 allows for "game playing" by the utilities?
3 A. If there is a common understanding of what is being updated, it should be
4 straight-forward for parties to perform a meaningful review of the model inputs.
5 Utilities receive no unfair benefit through the use of contemporaneous inputs
6 other than being able to provide a more accurate price. Furthermore, the timing of
7 the pricing request is under the control of the QF developer, not the Company.
8 Q. Could prices could go up as well as down from updates?
9 A. Yes. Prices may either increase or decrease as a result of an update.
10 Q. Does the use of an annual model update schedule provide developers with the
11 opportunity to choose between the outdated price and a contemporaneous
12 price?
13 A. Yes. Developers are aware of changing market conditions and are responsive to
14 changes in prices. Unlike a utility which has no control over when requests are
15 made, a developer has the option to either request prices now or to wait until after
16 an annual update, depending on market conditions. This asymmetry would harm
17 retail customers and can easily be eliminated through the use of a
18 contemporaneously calculated price.
19 Q. Do you agree with Mr. Schoenbeck's proposal that the eligibility cap for
20 published prices should be set at 10MW nameplate capacity for all types of
21 QF projects, and that the IRP method should only be used for projects above
22 that cap?
23 A. No. The Company reiterates its position stated in the direct testimony of Ms.
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1 Brown that the eligibility cap for wind and solar QFs seeking published avoided
2 cost prices should remain at 100kW. The 100kW limit for wind and solar QFs is
3 an appropriate tool to ensure accurate pricing developed using the IRP method
4 and to remove the incentive for larger projects to disaggregate and seek higher
5 published prices.
6 Q. Please summarize your comments regarding model updates.
7 A. The retail customer impact of not using contemporaneous model inputs is
8 significant for ,,a large QF resource. The burden on a QF developer resulting from
9 using contemporaneous model inputs does not outweigh the potential impact of
10 inaccurate prices. Contemporaneous and comprehensive updates of model inputs
11 allow utilities to provide the most accurate pricing to QF developers at any point • 12 in time and ensure indifference to retail customers.
13 Choice of Model
14 Q. Please summarize Mr. Schoenbeck's recommendation regarding the use of a
15 third-party model to develop avoided cost pricing.
16 A. Mr. Schoenbeck argues that internally developed models, such as PacifiCorp's
17 GRID model, require far too many exogenous inputs that can influence avoided
18 cost pricing and that utilities should be required to use a third-party model, such
19 as AURORA.
20 Q. How do you respond to Mr. Schoenbeck's recommendation?
21 A. Mr. Schoenbeck's recommendation is unfounded. The GRID model has
22 undergone extensive review in regulatory proceedings and is the same model that
23 is used by the Company in Idaho (and the five other jurisdictions served by the
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0 1 Company) to develop net power costs in rate making proceedings.
2 Q. Does PacifiCorp provide access to the GRID model for others to review?
3 A. Yes. PacifiCorp provides access and support for the GRID model. This allows
4 developers to perform a detailed review of all of the model inputs and outputs.
5 Timing of Capacity Payments
6 Q. Please explain your understanding of Staff witness Dr. McHugh's proposal of
7 when to include capacity payments under the proposed SAR methodology.
8 A. Dr. McHugh proposes to include capacity payments under the SAR methodology
9 in the year in which a utility's IRP load and resource balance shows that the
10 utility becomes capacity deficient. She distinguishes the capacity deficiency by
11 summer or winter season, and bases a resource-specific capacity payment on the
. 12 ability of that resource to contribute during the deficient season's peak.
13 Q. Are any other recommendations made regarding the trigger for applying a
14 capacity payment?
15 A. Yes. Mr. Schoenbeck proposes that Idaho Power should determine the timing of
16 capacity payments based on the results from its loss of load expectation study
17 rather than basing it on the results of its IRP load and resource balance.
18 Q. Do you agree with either proposal related to the timing for including a
19 capacity payment?
20 A. No. As demonstrated in PacifiCorp's IRP, the Company has access to a variety of
21 wholesale electricity market hubs that provide flexibility around the timing of
22 procuring capacity resources. In the Company's 2011 IRP Update the load and
23 resource balance using existing resources indicates the Company is peak deficit
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1 beginning in 2014, excluding planning reserves. A loss of load study is utilized to
2 determine the level of planning reserves required, which then influences the
3 preferred resource portfolio. In PacifiCorp's IRP Update, new CCCT resources
4 are projected to be added in 2014 and 2016. However, because the 2014 resource
5 has already gone through the procurement process and is currently under
6 construction, the next deferrable capacity resource in the Company's portfolio is
7 in 2016. Consistent with the IRP, capacity payments should be included in
8 avoided costs coincident with the timing of next deferrable resource.
9 Q. Has this issue been addressed recently in any other state served by
10 PacifiCorp?
11 A. Yes. In Docket UM 1396, Order No. 10-488, the Oregon Commission determined
' 12 that "the start date of the first 'major resource acquisition' in the action plan of the
13 most recent acknowledged IRP demarcates the resource 'sufficiency' and
14 'deficiency' periods."
15 Q. Do you agree with Dr. Reading's assertion that the Company's IRP is not
16 subject to sufficient scrutiny to warrant its use as an input into the avoided
17 cost process?
18 A. No. PacifiCorp agrees with Avista witness Mr. Clint Kalich and Staff witness Dr.
19 McHugh that today's IRPs are developed with input from the public, regulators,
20 and various other interested parties and should be relied upon in the development
21 of avoided cost prices. Given the six-state nature of PacifiCorp's system,
22 development of the Company's IRP is a rigorous process and the results receive a
23 significant amount of scrutiny, not just in Idaho but across our service territory.
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Q. Does this conclude your testimony?
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(The following proceedings were had in
open hearing.)
(Rocky Mountain Power Exhibit No. 201,
having been premarked for identification, was admitted into
evidence.)
6 MR. SOLANDER: And Mr. Dickman is available for
7 cross-examination.
CROSS-EXAMINATION
BY MR. WALKER:
Q. Mr. Dickman, could you -- could you please tell
us if you know how many contracts PacifiCorp has with QF
projects on its entire system?
A. I don't have a number from the number of QFs on
the entire system. I know that in Idaho, we have approximately
or will have approximately 18 by the end of this year.
Q. And do you know how many megawatts of QF
generation exist on PacifiCorp's system?
A. Again, just for Idaho is all that I have with me
today. I believe as of today, it's approximately 67 or 68
megawatts, and by the end of the year it will be 187.
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COMMISSIONER SMITH: Thank you. Let's start with
Mr. Walker.
MR. WALKER: Thank you, Madam Chair.
HEDRICK COURT REPORTING DICKMAN (X)
P. 0. BOX 578, BOISE, ID 83701 Rocky Mountain Power
Q. Do you know how that compares proportionately to
PacifiCorp' s load?
A. Again, just round figures, I believe PacifiCorp
load in Idaho is somewhere between 4- and 600 megawatts
depending on the season, and then system-wide, somewhere around
10- or 11,000 megawatts, subject to check.
MR. WALKER: No further questions, Madam Chair.
COMMISSIONER SMITH: Do you have any questions,
Mr. Andrea?
MR. ANDREA: Yes, Madam Chair, just one.
CROSS-EXAMINATION
BY MR. ANDREA:
Q. Mr. Dickman, can you look at page 3 of your
rebuttal testimony, starting on line 22.
A. Yes.
Q. It states: For PacifiCorp in particular, in
order to maintain consistency within the GRID model used for
the IRP methodology, updating the cost of fuel also requires
updating the forecast market prices for electricity.
Is that correct?
A. That's correct.
Q. Can you explain just kind of generally why it's
particularly important for PacifiCorp to update market prices
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HEDRICK COURT REPORTING DICKMAN (X)
P. 0. BOX 578, BOISE, ID 83701 Rocky Mountain Power
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for electricity when fuel costs are updated?
A. Yes. The intent was to clarify that my
understanding of other net power cost models -- for example,
AURORA -- calculate the forward market prices for electricity
internally. They are automatically updated when other updates
as the forward price of natural gas is inserted into the model.
The GRID model used by PacifiCorp is different in that the user
has to manually update both the forward price for natural gas
and the forward price for electricity. So we want to be clear
that both are required and should be put as allowable updates
in the IRP methodology.
Q. Thank you, Mr. Dickman.
MR. ANDREA: I don't have anything further.
COMMISSIONER SMITH: Ms. Sasser, do you have
questions?
MS. SASSER: A couple. Thank you, Madam Chair.
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CROSS-EXAMINATION
BY MS. SASSER:
Q. Mr. Dickman, in the direct testimony of
Ms. Brown -- just one clarification -- page 12 of Ms. Brown's
direct testimony, around line 6 or 7, you're referencing
different types of resources and you speak to a hydro resource.
Can you clarify as to whether that's a canal drop hydro or run
211
HEDRICK COURT REPORTING DICKMAN (X)
P. 0. BOX 578, BOISE, ID 83701 Rocky Mountain Power
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MR. ARKOOSH: I do not. Thank you, Madam Chair.
COMMISSIONER SMITH: Williams.
MR. R. WILLIAMS: No questions.
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of river hydro?
A. Yes. I believe when we calculated that number,
we used run of river hydro plants.
Q. Okay, thank you. And then on page 5 in your
rebuttal testimony, you speak to the frequency of model
updates, and beginning at page 6 -- or, line 16, page 5, of
your rebuttal, you say: PacifiCorp recommends updating all
modeling inputs, other than incremental resource additions
outlined in the IRP preferred portfolio, at the time the QF
pricing is prepared.
So, is it your testimony that you would update
avoided costs for the impacts of proposed QFs, or only QF
contracts that had been signed?
A. We would only include QF contracts that had been
signed in the calculation of the avoided cost, but we would
update the modeling inputs such as forward price curves, new
purchase or sale contracts that had been executed, to calculate
the avoided cost for a new pricing request from a QF.
Q. Okay.
MS. SASSER: That's all I have. Thank you.
COMMISSIONER SMITH: Mr. Arkoosh, do you have
questions?
HEDRICK COURT REPORTING DICKMAN (X)
P. 0. BOX 578, BOISE, ID 83701 Rocky Mountain Power
Madam Chair.
COMMISSIONER SMITH: Mr. Uda.
MR. UDA: No questions, Madam Chair.
COMMISSIONER SMITH: Miller has already passed.
Mr. Richardson.
MR. RICHARDSON: No questions, Madam Chairman.
COMMISSIONER SMITH: Ms. Nelson.
MS. NELSON: I'll speak up. No questions,
Thank you.
MR. OTTO: No questions, Madam Chair.
COMMISSIONER SMITH: Questions from the
Commission.
COMMISSIONER REDFORD: No.
COMMISSIONER KJELLANDER: No.
COMMISSIONER SMITH: Wow. I take it there's no
redirect.
MR. SOLANDER: No redirect, ma'am, and I would
ask that Mr. Dickman be excused from the remainder of the
proceeding.
COMMISSIONER SMITH: Would there be any objection
to excusing Mr. Dickman from the remainder of the proceedings?
Seeing none, he's excused.
MR. SOLANDER: Thank you.
COMMISSIONER SMITH: Thank you.
(The witness left the stand.)
MR. SOLANDER: Are you ready for me?
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HEDRICK COURT REPORTING DICKMAN (X)
P. 0. BOX 578, BOISE, ID 83701 Rocky Mountain Power
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1 COMMISSIONER SMITH: Yes.
2 MR. SOLANDER: Rocky Mountain Power calls
3 Paul Clements to the stand.
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5 PAUL CLEMENTS,
6 produced as a witness at the instance of Rocky Mountain Power,
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being first duly sworn, was examined and testified as follows:
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DIRECT EXAMINATION
BY MR. SOLANDER:
Q. Good morning.
A. Good morning.
Q. Could you please state your name for the record?
A. Yes. Paul H. Clements, spelled C-L-E-M-E-N-T-S.
Q. And by whom are you employed and in what
capacity?
A. I'm employed by PacifiCorp as a senior power
marketer.

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Q. And are you the same Paul Clements who filed
direct and rebuttal testimony in this proceeding, along with
Exhibit 202 to direct testimony?
A. Yes, I am.
Q. Do you have any corrections to that testimony at
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HEDRICK COURT REPORTING CLEMENTS (Di)
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A. I do not.
MR. SOLANDER: At this time, I'd ask that the
direct and rebuttal testimony of Mr. Clements, including
Exhibit 202 to the direct testimony, be spread upon the record
as if read.
COMMISSIONER SMITH: If there is no objection, we
will spread the prefiled direct and rebuttal testimony of
Mr. Clements upon the record as if it had been read, and admit
Exhibit 202.
(The following prefiled direct and
rebuttal testimony of Mr. Clements is spread upon the record.)
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HEDRICK COURT REPORTING CLEMENTS (Di)
P. 0. BOX 578, BOISE, ID 83701 Rocky Mountain Power
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Please state your name, business address and present position with
PacifiCorp, dba Rocky Mountain Power Company (the "Company").
My name is Paul H. Clements. My business address is 201 S. Main, Suite 2300,
Salt Lake City, Utah 84111. My present position is Originator/Power Marketer for
PacifiCorp Energy. PacifiCorp Energy and Rocky Mountain Power are divisions
of PacifiCorp (hereinafter referred to as the "Company" or "Rocky Mountain
7 Power").
8 Q. How long have you been in your present position?
9 A. I have been in my present position since December 2004.
10 Q. Please describe your education and business experience.
11 A. I have a B.S. in Business Management from Brigham Young University. I have
. 12 been employed with PacifiCorp since 2004 as an originator/power marketer
13 responsible for negotiating qualifying facility contracts, negotiating interruptible
14 retail special contracts, and managing wholesale or market-based energy and
15 capacity contracts with other utilities and power marketers I also worked in the
16 merchant energy sector for approximately six years in pricing and structuring,
17 origination, and trading roles for Duke Energy and Illinova.
18 Purpose and Summary of Testimony
19 Q. What is the purpose of your testimony?
20 A. I present the Company's recent experience with Non-Standard Qualifying Facility
21 ("QF") contracts. Non-Standard QFs are projects that do not qualify for published
22 rates. In addition, I propose a new tariff Schedule 38, provided as Exhibit No.
23 202, to govern the Non-Standard QF contracting procedures in Idaho going
. 216
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1 forward and I will explain the provisions of this new tariff. Lastly, I provide

2 comments on Environmental Attribute ownership as it pertains to QFs.

3 Q. Please summarize your testimony.

4 A. The Company has, over the past five years, received five requests for indicative

5 pricing for projects that do not qualify for published rates for qualifying facilities.

6 The Company used the IRP methodology, as established in IPC-E-95-9, to

7 calculate indicative avoided costs in response to the requests. Rocky Mountain

8 Power witness Ms. Kelcey Brown provides an overview of the methodology and

9 the Company's proposal for continued use of the IRP methodology. The IRP

10 methodology along with the contracting procedures contained in the proposed

11 tariff Schedule 38 will provide fair pricing and contracting processes for Non-

12 Standard QFs in Idaho and will render existing retail customers indifferent as to

13 whether energy is purchased from QFs or supplied by Rocky Mountain Power

14 from other sources in the future. Regarding Environmental Attribute ownership,

15 the Company's position is that the Company owns all Environmental Attributes

16 generated by QFs.
17 Proposed Tariff Schedule 38

18 Q. Please explain why the Company is proposing tariff Schedule 38.

19 A. Tariff Schedule 38 is a new tariff for Non-Standard QF projects that will provide

20 the steps and timeframe that both the Company and a proposed Non-Standard QF

21 work through to determine indicative or estimated avoided cost prices for a

22 proposed QF project. The tariff will facilitate communication between the

23 Company and potential QFs as they work through the negotiation process. The
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1 tariff clearly identifies the information required from the QF and the timeline in

2 which the QF will receive indicative pricing. The tariff codifies in Idaho the

3 process that Rocky Mountain Power formally uses in Utah and Wyoming and has

4 informally been using in Idaho for several years Through experience in

5 implementing the process in other states, the Company believes the formal

6 process proposed in Schedule 38 is an efficient and productive process for both

7 the Company and potential QFs.

8 Q. Does the Company have a formal Non-Standard QF negotiation procedure in

9 other jurisdictions?

10 A. Yes. The Company's Schedule 38 Non-Standard QF contract negotiation process

11 is in place in Utah,' Oregon and Wyoming.

. 12 Q Please explain the proposed tariff Schedule 38

13 A. Schedule 38 - Avoided Cost Purchases from Non-Standard Qualifying Facilities,

14 is based on the output of a work-group that was established in 2002 in Utah

15 Docket 02-035-Ti 1 addressing issues similar to those being addressed in Case

16 No GNR-E-1 1-03 in Idaho The work group included many parties with similar

17 interests to those in this Case, who participated in the development and

18 negotiation of the procedures in this tariff. The general purpose of Schedule 38 is

19 to provide the steps and timeframe that both the Company and a proposed QF

20 work through to determine indicative avoided cost pricing for a proposed QF

21 project. The tariff clearly lays out the information the Company requires be

22 provided by the developer in order for the Company to prepare indicative prices
1 As an example the Utah tariff can be found at the following internet address:
. http:llwww.rockymountainpower.neilcontentldamlrockyjnountain_power/doc/About_UslRates_and_Regu
1ationIUtahIAroved_TariffsIRate_SchedulsIAvoided_cost_pses_from_Qualifying_Facilities.pdf.
Clements, Di - 3
Rocky Mountain Power
for a proposed QF project.
Even a developer of a QF project in the conceptual stage should have most
of the information collected and available to provide to the Company because the
information required in Schedule 38 is necessary for the design, development,
financing, and construction of the QF project. As outlined by the procedure, QF
projects that provide the required details regarding their projects upfront have a
much lower probability of experiencing a delay in the development of indicative
prices. The Company works very closely with the QF in this initial step by
completing due diligence and feedback on the information. Once the information
is agreed to by both parties, the Company completes its pricing step. As outlined
by the tariff, the parties then follow the timelines and process for completing
negotiation of a Power Purchase Agreement ("PPA"). The timeline for the various
steps in the process is as follows:
1.Indicative pricing is provided within 30 days following receipt of all
required information.
2.A draft PPA is provided within 45 days following receipt of all
required additional information after indicative pricing has been
provided.
3.A final PPA is provided within 45 days of agreement by both parties
on all material terms in the PPA.
4.Counterparties must wait 60 days after one party gives notice that the
parties are unable to reach agreement on a final PPA before filing a
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complaint with the Commission on any specific contract terms not
agreed upon.
What contract terms and conditions will be included by the Company in a
PPA that is provided as part of the Schedule 38 process?
The terms and conditions of the QF PPA will be similar to those terms and
conditions obtained from recent similarly-sized QFs and third party PPAs and will
also take into account the terms and conditions established by the Commission in
Case No. GNR-E-11-01.
How does the proposed Idaho Schedule 38 compare to the current Wyoming
and Utah Schedules 38?
The proposed Idaho Schedule 38 is similar to the Wyoming Schedule 38 Rocky
Mountain Power established the Wyoming Schedule 38 in late 2011 and it reflects
the most up-to-date process that has been refined through experience to provide
the most efficient process for communication between the QF and the Company.
The Utah Schedule 38 has been in place for several years and is slightly different
than the Wyoming Schedule 38 and the proposed Idaho Schedule 38. The
proposed Idaho Schedule 38 provides 45 days for delivery of the draft PPA, the
Utah Schedule 38 provides 30 days. The proposed Idaho Schedule 38 also
establishes a 45 day timeline for delivery of a final PPA, the Utah Schedule 38
does not provide a timeline for delivery of a final PPA. Finally, the proposed
Idaho Schedule 38 establishes a 60 day waiting period before a complaint with the
Commission on contract terms can be filed, the Utah Schedule 38 does not
address Commission complaint filings.
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1 Q. Has Schedule 38 worked as it was intended in the other states where it has
2 been implemented?
3 A. Yes. Schedule 38 has provided a framework under which the QF developer knows
4 what is required in order to obtain indicative pricing. Even in other states where
5 there is no formal Schedule 38, the Company uses this schedule as a general road
6 map with the developer who is proposing a Non-Standard QF. It provides the QF
7 developer a clear understanding on what is needed to secure indicative prices
8 from the Company. If they wish to proceed with the project or renew their
9 contract, the tariff establishes a procedure that both parties follow throughout the
10 contract negotiations. To work effectively, Schedule 38 requires specific and
11 detailed information from the QF regarding their proposed project. A QF
. 12 developer that comes to the Company with vague requests or insufficient details
13 will go through a series of due diligence meetings until all data is agreed to by
14 both parties. The Company is not in a position to provide indicative pricing
15 without sufficient and clear project details. Once the prices are prepared and
16 accepted by the QF, there is a set timeframe for the Company to provide an initial
17 draft PPA for contract negotiations. The QF knows and understands the steps and
18 timeframe to complete a power purchase agreement.
19 Q. Have you provided as an exhibit a proposed Schedule 38 for Idaho?
20 A. Yes. Exhibit No. 202 is the Company's proposed Schedule 38 for Idaho.
21 Environmental Attribute Ownership
22 Q. What is an Environmental Attribute?
23 A. The "Environmental Attribute" of electricity generation is a collection of the
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1 environmental and other positive, non-energy attributes of renewable generation.
2 Environmental Attributes include not only the avoided emissions characteristics
3 and the proof of generation of renewable energy, but also the right to make a
4 claim with respect to that energy; specifically, the exclusive right to claim to have
5 performed the social and environmental good of generating renewable, as
6 opposed to fossil fuel, energy. A key value of energy from renewable resources
7 being purchased is the "renewableness" of the energy. The Environmental
8 Attributes of the energy that give it the unique characteristic of being "renewable"
9 can be separated from the energy itself and traded by defining what is called a
10 "green tag," "renewable energy certificate," "renewable energy credit," "green
11 attribute," or "tradable renewable energy credits."
. 12 Q. Why are you providing testimony on the issue of Environmental Attribute
13 ownership as it pertains to QFs?
14 A. The Company understands that the Commission may elect to address
15 environmental attribute ownership in conjunction with this Case.
16 Q. What is Rocky Mountain Power's recommendation on Environment
17 Attribute ownership as it pertains to Environmental Attributes generated by
18 QFs?
19 A. Environmental Attributes generated by a QF project should go to the utility
20 whenever that QF sells energy to the utility and receives compensation for that
21 energy at approved avoided cost rates.
22 Q. How is the Company's recommendation supported by the intent of PURPA?
23 A. Section 210 of PURPA requires utilities to buy power from generation fueled by
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1 specific resources (biomass, solar, wind, waste, and geothermal) or in specific
2 configurations (e.g., cogeneration). If those generators were not powered by those
3 specific resources, the utilities would not be required to purchase that energy
4 under PURPA. Furthermore, the meters between the QF and the utility's system
5 have always shown the energy from that renewable resource flowing to the utility.
6 Q. Does Rocky Mountain contend it could be paying above avoided cost for
7 Environmental Attributes if it were required to pay a QF separately for such
8 Environmental Attributes?
9 A. Yes. It is the Company's position that if Rocky Mountain Power were to pay a QF
10 separately for the Environmental Attribute, Rocky Mountain Power and its
11 customers would in effect be paying twice for that attribute and thus pay above
. 12 avoided cost.
13 Q. Please further explain your position.
14 A. PURPA contains no requirement that a purchasing utility pay twice for what it has
15 already bought. PURPA requires that utilities purchase from QFs, and QFs are
16 afforded that designation because of fuel use or efficiency criteria. A utility must
17 purchase from a QF that is also an eligible renewable energy resource because of
18 the generation's Environmental Attributes. Without these characteristics, the
19 generator would not be able to require the utility to purchase its energy at all. In
20 other words, it is only by virtue of the existence of the Environmental Attributes
21 that facilities are deemed QFs and utilities become obligated to purchase their
22 power. In the case of eligible renewable energy resource QFs, these
23 Environmental Attributes are the essence of the requirements to purchase the
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output, and is therefore part of what the utility is buying with the payment of
avoided costs. If Rocky Mountain Power does not get the QF Environmental
Attribute, it is not receiving the very characteristic that enabled the facility to
achieve its QF status, and which thereby triggered the utility's obligation to
purchase the output from the facility.
If the utility is in fact buying energy from a differentiated renewable
resource, can that resource truly sell its Environmental Attributes to third
parties?
Although some QFs do purport to sell Environmental Attributes to third parties,
any such sale is defective for the following reasons:
(1)a core aspect of the Environmental Attributes is the exclusive right to
claim to have purchased generation from a particular renewable resource
generating facility;
(2)pursuant to a QF contract, the utility agrees to buy energy from a
particular renewable resource generating facility (as opposed to
undifferentiated energy in bulk at a market delivery point); and
(3)since the utility is buying the energy from that particular facility, no
one else can truthfully claim to be doing so.
frrespective of PURPA, double-counting of renewable generation is false
advertising at best and fraud at worst. Simply because one attribute of what has
always been sold pursuant to PURPA contracts subsequently acquires a separate
market value does not mean that particular attribute now warrants separate
compensation, just as it does not mean that the attribute has been, or is being,
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1 transferred without consideration. A purchasing utility under a QF contract is not
2 buying undifferentiated energy from the grid; it is buying energy that is very
3 particularly differentiated to such an extent that the utility is required by law to
4 buy it at the special price known as "avoided cost". Under PURPA, the utility has
5 the obligation of purchasing energy from a differentiated resource at the utility's
6 avoided cost. Absent utility ownership of all the differentiated resource's
7 attributes, the utility is paying higher than its true avoided cost.
8 Q. What conclusion can you draw from your analysis of the intent of PURPA
9 and how it applies to the issue of Environmental Attribute ownership in QF
10 contracts?
11 A. In terms of PURPA, any power purchase agreement securing power from an
. 12 eligible renewable energy resource should therefore credit the associated
13 Environmental Attributes to the purchasing utility.
14 Q. Does this conclude your direct testimony?
15 A. Yes.
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Q.
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Please state your name, business address and present position with the
Company (also referred to as Rocky Mountain Power).
My name is Paul H. Clements. My business address is 201 S. Main, Suite 2300,
Salt Lake City, Utah 84111. My present position is Originator/Power Marketer for
PacifiCorp Energy. PacifiCorp Energy and Rocky Mountain Power are divisions
of PacifiCorp (hereinafter referred to as the "Company" or "Rocky Mountain
Power")
40
8 Q. How long have you been in your present position?
9 A. I have been in my present position since December 2004.
10 Q. Please describe your education and business experience.
11 A. I have a B.S. in Business Management from Brigham Young University. I have
12 been employed with PacifiCorp since 2004 as an originator/power marketer
13 responsible for negotiating qualifying facility contracts, negotiating interruptible
14 retail special contracts, and managing wholesale or market-based energy and
15 capacity contracts with other utilities and power marketers. I also worked in the
16 merchant energy sector for approximately six years in pricing and structuring,
17 origination, and trading roles for Duke Energy and Illinova.
18 Q. Have you previously filed testimony in this proceeding?
19 A. Yes. I filed direct testimony in which I presented the Company's recent
20 experience with Non-Standard Qualifying Facility ("QF") contracts. Non-
21 Standard QFs are projects that do not qualify for published rates. In addition, I
22 proposed a new tariff Schedule 38 to govern the Non-Standard QF contracting
23 procedures in Idaho going forward. I also explained the provisions of this new
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1 tariff. Lastly, I provided comments on Environmental Attribute ownership as it
2 pertains to QFs.
3 Purpose and Summary of Testimony
4 Q. What is the purpose of your testimony?
5 A. I will provide the Company's response to the testimony of Staff witness Mr. Rick
6 Sterling and Clearwater Paper CorporationlJ.R. Simplot Company/Exergy
7 Development Group of Idaho, LLC witness Dr. Don Reading regarding several
8: items related to QF contracting procedures and contract terms.
9 Q. Please summarize your testimony.
10 A. My testimony discusses and recommends the following:
11 1. The Company's proposed Schedule 38 should be implemented. If a
' 12 separate docket is opened for review and comment, Schedule 38 should be
13 implemented on an interim basis.
14 2. Utilities should not be required to execute QF contracts with firm pricing
15 earlier than 36 months prior to the QF's expected commercial operation
16 date.
17 3. A non-firm standard contract for Rocky Mountain Power is not necessary
18 and Rocky Mountain Power should not be required to file a tariff similar
19 to Idaho Power's Schedule 86.
20 4. QFs should not be entitled to any refund of network transmission upgrades
21 since doing so would provide a subsidy to QFs and the price for QF
22 generation will be in excess of the utility's avoided costs.
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1 Responses to Testimony of Rick Sterling
2 Q. PacifiCorp filed and recommended the Commission implement a proposed
3 tariff (Schedule 38) that specifies contracting procedures and rules for QF
4 contracts. Mr. Sterling recommends that a separate docket be opened for
5 review and comment on the specific details of a tariff for each utility.' Do
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you agree with this approach?
No. The Company's proposed Schedule 38 as filed in Exhibit No. 202 is ready for
implementation. It has been in place in other states in a similar form for several
years and has proven to be a useful and effective tool for management of the
contracting process for QFs. The Company recommends the Commission approve
the Company's proposed Schedule 38 in conjunction with this docket. However,
should the Commission order a separate docket for review and comment on
Schedule 38, the Company requests that it be allowed to operate under the
provisions of its proposed Schedule 38 on an interim basis until a permanent tariff
is approved by the Commission.
Mr. Sterling does not agree with Avista's proposal that rates contained in a
PURPA contract not be locked in more than two years ahead of commercial
18 operation, instead stating that five years after contract approval is a
19 reasonable period of time to preserve rates contained in an initial contract.2
20 Do you agree with Mr. Sterling's recommendation?
21 A. No. Holding contract prices open for up to five years increases price risk to
22 customers and, based on the Company's experience, is not needed for QF
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1 Direct Testimony of Rick Sterling dated May 4, 2012, page 32 line 20 through page 33 line 4.
2 Direct Testimony of Rick Sterling dated May 4, 2012, page 33 line 5 through page 35 line 1.
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1 development. Holding contract prices open for five years increases the risk that

2 avoided costs could change significantly from the time the contract was executed

3 to the time the resource comes online and begins to provide energy to customers.

4 A QF contract should be treated as a binding obligation for a project that is

5 expected to be developed and come online in the near future, not an option for a

6 project that is not ready to come online and requires significant further

7 development before construction can begin. Once a contract is signed, the QF

8 should be allotted adequate time to finalize financing and development efforts and

9 then complete construction of the project. Based on the Company's experience,

10 five years is too long. For most resource types, final development work and

11 construction can be completed in less time than five years. Customers should not

. 12 be exposed to potential price movements while a QF developer evaluates whether

13 it can meet its obligations under a signed contract. A signed contract should only

14 occur once a developer is certain it can meet its contractual obligation. In most

15 cases, five years is not required from contract execution to project online date,

16 and it would be unreasonable for customers to bear the price risk for such a long

17 period of time.

18 Q. What do you recommend regarding timing for locking in pricing in QF

19 contracts?

20 A. A QF contract should allow adequate time for the developer to finalize

21 development activities and complete construction after execution of a contract

22 with firm pricing. This time period may vary depending on the type of resource

23 since construction times differ slightly for each resource type. However, in most
229 Clements, Re - 4
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1 cases, it is reasonable to assume a combined heat and power, wind, solar or other

2 type of QF can be constructed in 18 to 24 months once development work is

3 complete. And most development work, including arranging financing and

4 procuring major equipment, can be completed within six to 12 months of

5 execution of a QF contract. Therefore, it is reasonable to expect a QF to come

6 online within 24 to 36 months of executing a contract with firm pricing. This

7 allows adequate time to complete their interconnection, secure financing and

8 construct the project.

9 Therefore, the Company recommends that utilities not be required to

10 execute contracts with firm pricing earlier than 36 months prior to the QF's

11 expected commercial operation date.

. 12 Q. How does your recommendation compare to what you have witnessed with

13 recent QF contracts the Company has executed?

14 A. The Company's experience with QF contracts in recent years demonstrates that

15 the 36 month timeline recommended by the Company is reasonable and will allow

16 QF development to continue without exposing customers to increased price risk.

17 Most projects are constructed and reach commercial operation less than 36

18 months after execution of a power purchase agreement. In fact, some projects are

19 online prior to executing a power purchase agreement. The table below shows the

20 contract execution date and actual online date for several recent QFs under

21 contract with the Company.
230 Clements, Re - 5
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Project Description Contract
Execution Date
Project
Online Date
Approximate #of Months
Between Contract Signing and QF
Online Date
60.9 MW Wind QF 7/14/2006 7/31/2008 25
79.8 MW Wind QF 10/26/2006 9/30/2008 23
16.5 MW Wind QF 5/26/2009 12/14/2009 7
18.9 MW Wind QF 6/20/2006 8/29/2008 26
5.0 MW Hydro QF 8/17/2009 10/4/2010 14
10.0 MW Biomass QF 1/2/2007 12/1/2007 11
107.4 MW Gas QF 2/21/2005 1/1/2005 -2
25.0 MW Gas OF 8/27/2004 4/16/2004 -4

1 As the data in the table demonstrates, new QF projects usually reach commercial

2 operation within 36 months of executing a contract. Thus 36 months is more than

3 adequate to complete construction of a project once a power purchase agreement

4 has been executed. Accordingly, utilities should not be required to execute
, 5 contracts earlier than 36 months before the expected online date.
6 Responses to Testimony of Don Reading
7 Q. Regarding the Company's proposed Schedule 38, Mr. Reading states the

8 deadlines in the proposed Idaho Schedule 38 are far longer than the

9 deadlines in the Schedule 38 tariffs in the Company's other states.3 Is his

10 statement accurate?

11 A. No. The deadlines in all of the Company's Schedule 38 tariffs are similar. The

12 Company has proposed a 45 day response period for indicative pricing in the

13 proposed Idaho Schedule 38. Some other states' Schedule 38 tariffs, such as Utah

14 and Wyoming, call for a 30 day response period. The Company believes this 45

15 day response period is reasonable given the fact that it at times receives a large

16 number of indicative pricing requests. The 45 day response period allows the
is 3 Direct Testimony of Don Reading dated May 4, 2012, page 61, lines 14-16.
231 Clements, Re - 6
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1 Company adequate time to respond to indicative pricing requests within the tariff

2 deadlines even during periods in which it receives multiple indicative pricing

3 requests.

4 Q. Has the Company experienced time periods in which it has received multiple

5 indicative pricing requests?

6 A. Yes. At the time of preparation of this testimony, the Company had approximately

7 20 indicative pricing requests at some stage in the Schedule 38 contracting

8 process.

9 Q. Mr. Reading has suggested an alternative proposal to your filed Schedule 38

10 in which he suggests using the standard contracting tariffs approved by the

11 Public Utility Commission of Oregon or "some form of reasonable substitute

' 12 with similar requirements. ,5 Would you consider the Schedule 38 you

13 proposed for Idaho to have similar requirements to Oregon Schedule 38?

14 A. Yes. Both tariffs are similar in structure and in deadlines for the various stages of

15 the contracting process.

16 Q. Is it your opinion that the Company's proposed Idaho Schedule 38 meets Mr.

17 Reading's requirement that it be "some form of reasonable substitute with

18 similar requirements"?

19 A. Yes.
. 4 Direct Testimony of Don Reading dated May 4, 2012, page 62, lines 2-4.
Direct Testimony of Don Reading dated May 4, 2012, page 63, line 5.
232 Clements, Re - 7
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I Q. Mr. Reading recommends that Rocky Mountain power file a non-firm

2 standard contract similar to Idaho Power's Schedule 86.6 Have any Idaho

3 QFs in recent history requested a non-firm standard contract from Rocky

4 Mountain Power?

5 A. No.

6 Q. Do you believe a tariff including a non-firm standard contract is necessary

7 for Rocky Mountain Power?

8 A. No. The Company has not seen much interest from QFs for a non-firm standard

9 contract. Furthermore, Rocky Mountain Power's proposed Schedule 38 provides a

10 clear process by which a customer can obtain a contract, either firm or non-firm,

11 in a timely manner. The Company does not believe a tariff similar to Idaho

" 12 Power's Schedule 86 is necessary since a QF has the opportunity to obtain a non-

13 firm contract under Schedule 38.

14 Q. Mr. Reading recommends that a QF be entitled to 100 percent refund of

15 network transmission upgrades.7 Is this proposal reasonable and does it

16 maintain ratepayer indifference?

17 A. No. Mr. Reading's recommendation that QFs be entitled to 100 percent refund of

18 network transmission upgrades should be rejected. His proposal does not provide

19 incentive for developers to make cost effective generation siting decisions and

20 does not maintain ratepayer indifference. If the developer wants the benefit of

21 utility avoided cost rates, the developer should be obligated to pay for all the

22 interconnection and integration transmission upgrades required to allow him to
. 6 DfreCt Testimony of Don Reading dated May 4, 2012, page 65, lines 16-19.
7 Direct Testimony of Don Reading dated May 4, 2012, page 67, lines 6-8.
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1 deliver energy to the utility, at which time the purchase obligation under PURPA

2 occurs. The utility and its customers should not be required to pay any

3 transmission costs that are incurred by the QF developer prior to the purchase

4 obligation being met.

5 If the developer wishes to sell its output at market rates on a competitive

6 basis in the wholesale power market comparable to other independent power

7 producers, it should be treated similar to other independent power producers and

8 receive the financial treatment under the current FERC procedures.

9 In summary, if the QF interconnection and transmission upgrade costs are

10 passed along to utility customers by way of a refund to the QF, the QF has been

11 provided a subsidy and the price for QF generation will be in excess of the

' 12 utility's avoided costs.

13 Q. Does this conclude your testimony?

14 A. Yes.
~ 0 234
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S 1 (The following proceedings were had in
2 open hearing.)
3 (Rocky Mountain Power Exhibit No. 202,
4
having been premarked for identification, was admitted into
5 evidence.)
6 MR. SOLANDER: And Mr. Clements is available for
7 cross-examination.
8 COMMISSIONER SMITH: All right. Mr. Walker.
MR. WALKER: No questions for Mr. Clements,
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Madam Chair.
MR. ANDREA: No questions, Madam Chair.
COMMISSIONER SMITH: Ms. Sasser.
MS. SASSER: No, Madam Chair.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: Yes, Madam Chair.
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CROSS-EXAMINATION
BY MR. OTTO:
Q. Good morning.
A. Good morning.
Q. Or I guess almost afternoon. Mr. Clements, you
submit some testimony talking about the ownership of renewable
attributes, or REC5. Is that true?
A. That's true.
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Q. Is that a legal issue or a factual issue, the
ownership of RECs?
A. If you're asking me for a legal opinion, I
probably am not qualified for that, but my understanding and my
testimony states that it's a matter that the Idaho Public
Utilities Commission can decide.
Q. So as you think of the problem, or the issue, do
you think the ownership of REC5 is an issue of fact, or do you
think that there are legal conclusions that need to be made
about who owns those?
A. I think there are policy determinations that need
to be made about who owns the RECs.
Q. And you offer some policy suggestions?
A. Yes.
Q. Okay. One of those -- and I'm going to -- I'm
going to kind of summarize what your position and -- but I want
you to tell me if that's a correct summary or not. I'm just
trying to get the core of it, so not trying to put words in
your mouth.
A. Okay.
Q. But one of your points is that -- I'm going to
use Rocky Mountain Power, I'm used to that.
If Rocky Mountain Power pays twice for a REC and
the avoided cost -- I'm sorry, let me back up for a second, so
let me retract that.
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S i Essentially, you're arguing that a REC or the
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MR. SOLANDER: I'm sorry, Madam Chair, can he
refer to a page number in Mr. Clements' testimony?
MR. OTTO: Sure. I will.
Q. BY MR. OTTO: This is your direct testimony, and
we're at page 8, and beginning on line 19 through about 22
there's a sentence that says "In other words."
A. Do you want me to read that section?
Q. Sure. Sure.
A. Sure. I'd probably back up to line 16 --
Q. Sure.
A. -- where I state: A Utility must purchase from a
QF that is also an eligible renewable energy resource because
of the generation's environmental attributes. Without these
characteristics, the generator would not be able to require the
Utility to purchase its energy at all. In other words, it is
only by virtue of the existence of the environmental attributes
that facilities are deemed QFs and Utilities become obligated
to purchase their power.
I think that's probably the best summary of my
position right there.
Q. Fair enough. Can you point to any authority or a
Decision that's ever agreed with that policy recommendation?
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A. What do you mean by "authority"? Are you saying
am I aware of an instance where the RECs go to the Utility?
Q. No. Are you aware of an instance that the
environmental attributes, only by virtue of the existence of
the attributes are the Utilities obligated to purchase their
output? Has that issue, to your knowledge, been presented to,
say, the Federal Energy Regulatory Commission?
A. Not exactly sure what you're asking. If you
could clarify the question?
Q. Well, what I'm asking is just what do you base
this recommendation on or this opinion on?
A. Well, we defined "environmental attributes"
earlier in my testimony. It's essentially the portion that, by
being a renewable project, it brings with it certain
environmental attributes and the Utility is obligated to
purchase the output of that project due to the fact that it is
renewable. And so it is the fact that the project is renewable
that creates the purchase obligation. And so if you want to
interchange the notion of "renewable" with "environmental
attributes," you can do so, but I would argue those two things
are identical or very similar.
Q. Where would you point to the authority or the
obligation that it is the environmental attribute specifically
that allows a developer to avail themselves of PURPA?
A. Well, again, I'm interchanging environmental
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attributes and renewable, referring to them as the same thing,
and I would say PURPA itself would be the regulation that I
would point to.
Q. In your preparing your testimony, did you review
any of the FERC Orders on PURPA and renewable energy, or did
you have any conversations with your counsel about that?
A. Yes, jointly with Counsel, we reviewed those
Orders.
Q. And do you recall how FERC has explained that
RECs are completely outside of PURPA?
MR. SOLANDER: Objection: There's no foundation
for that question.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: I believe he just laid the foundation
by -- I asked him whether he had reviewed the Orders or
discussed that, and he said he had; and I'm asking now his
opinion on what he recalls from those Orders.
COMMISSIONER SMITH: The witness can give his
opinion on what he recalls in the Orders.
THE WITNESS: Thank you, Madam Chair.
I don't recall any Orders that said that REC
ownership is outside of scope.
Q. BY MR. OTTO: Thank you. I would -- one other
topic: On page 9, it's a question that begins on line 6 and
your answer begins on line 9, obviously, but you say that a
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sale of environmental attributes to third parties is defective.
Is that true? Do you recall that in your
testimony?
A. I'm sorry, which page and which line again?
Q. This is page 9 of your direct testimony.
Beginning on line 9, your answer is -- well, you state that a
sale -- the sale of environmental attributes to third parties
is defective for the following reasons.
Do you stand by that testimony today?
A. I stand by the opinion as written in the
testimony, yes.
Q. So how --
A. And if I could spin on that answer, it's due to
double-counting. If we are said to be purchasing the renewable
attributes or to be receiving the renewable attributes of the
output of this facility, then that facility could not go and
sell those outputs to a third party. That would essentially be
double-counting those renewable attributes. And that was the
intent of the testimony there.
Q. Are you aware if Rocky Mountain Power makes
third-party sales of environmental attributes?
A. Yes, we do.
Q. And do you know what the kind of scale of those
things are?
A. Yes, generally.
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Q. Would you agree -- I think in the last rate case
Order for Idaho, the Stipulation was about $77 million in
third-party sales of environmental attributes. Does that sound
about in the ballpark?
A. I'm not familiar with that, but I would not be
surprised by that.
Q. It sounds in the ballpark?
A. Yes.
Q. So were those sales defective?
A. No, those sales were not defective, because those
were instances where we, by contract, had the attestations,
meaning we had legal ownership of the RECS per a contractual
agreement with the counterparty who produced those RECs.
Q. Does the energy flow with those sales?
A. In most instances, the energy does flow; in some
instances, it does not.
Q. So it's fine to have unbundled REC sales?
A. Yes, it is.
MR. OTTO: Thank you. That's all I have.
COMMISSIONER SMITH: All right. Ms. Nelson.
MS. NELSON: No questions, Madam Chair. Thank
you.
COMMISSIONER SMITH: Mr. Richardson.
COMMISSIONER SMITH: Thank you, Madam Chairman.
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1 CROSS-EXAMINATION
2
3 BY MR. RICHARDSON:
4
Q. Good morning, Mr. Clements.
5 A. Good morning.
6 Q. Start at page 6, line 23, of your direct
7 testimony. You provide a definition of "environmental
8 attributes," and the phrase is in quotes and is capitalized.
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Who are you quoting?
A. I'm strictly attempting to define -- excuse me --
the term environmental attribute to be used throughout my
testimony.
Q. So you're not quoting anyone?
A. No one in particular. I will add that the term
environmental attribute is a contract term that is used quite
frequently between counterparties in the industry, and it has
become a fairly well-known and well-defined term through
various contracts, so while I'm not quoting anything
specifically, we do use the term environmental attribute in
many of our contracts and it is a fairly well-known industry
term.
Q. And is that generally true for the other quoted
phrases in your answer there, beginning on line 23 on page 6?
A. Yes. If you're referring to "green tag,"
"renewable energy certificate," "renewable energy credit,"
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those are often used interchangeably, although there are some
nuances depending on which state you're in and what environment
you're in, but those are typically interchangeable terms.
Q. So on page 7 at line 19, you make the assertion
that environmental attributes generated by a QF project should
go to the Utility whenever that QF sells energy to the Utility
and receives compensation for that energy at approved avoided
cost rates. Do you see that?
A. Yes.
Q. And do you know how avoided cost rates are set in
Idaho?
A. In a general sense, yes, and I believe that's the
purpose of this proceeding is to establish that methodology.
Q. And so you're familiar with how this Commission
sets avoided cost rates?
A. Well, again, I believe that's the purpose of this
proceeding so -- but in a general sense, what the parties have
proposed, yes, I am familiar with what we have proposed.
Q. You know there's avoided cost rates in place
today in Idaho?
A. Yes.
Q. And do you know how those rates are set?
A. Yes, in a general sense, yes.
Q. Then you know that the rates only compensate the
developer for the avoided cost of energy and capacity.
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Correct?
A. I would agree that there is an energy and a
capacity component to the rates that QFs are paid, yes.
Q. And the question was you would agree that the
avoided cost rates only compensate the QF for avoided energy
and capacity. Correct?
A. I would not agree with your term "compensate."
would agree that there's a capacity and an energy payment.
What's included in that payment is up for this Commission to
decide.
Q. Is what?
A. Is for the Commission to decide.
Q. I'm talking about the rates that are in effect
today that the Commission has decided. Would you agree -- the
question is would you agree that the QF is only compensated for
avoided energy and capacity?
A. No.
Q. What else is the QF compensated with?
A. It is my position that the QF receives
compensation in exchange for selling their energy and capacity
to the Utility.
Q. And what's that bundle of compensation? What's
in it? Where did the -- how did the Commission come up with
that compensation number?
A. In terms of? Could you rephrase your question?
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Are you asking me to explain the QF pricing methodology?
Q. Yeah, I asked you earlier if you knew how this
Commission sets avoided cost rates, and you said that you did,
generally. Then I asked you if you would agree that the QF
avoided cost rates set by this Commission only compensate the
QF for energy and capacity. Would you agree with that?
A. No. I would argue that the compensation could
include environmental attribute as well.
Q. Does it?
A. There is no specific line item that -- in the
current methodology for environmental attributes, but that does
not mean that the capacity and energy price could not provide
compensation for that.
Q. I asked you if it did, and you said there is no
line item. Can you point to me where, in the Commission's
avoided cost Order setting avoided cost rates, where anything
other than avoided energy and capacity are provided to the QF?
A. Well, let me answer that another way, perhaps, so
we don't go round and round here:
To my knowledge, there's no specific item that
states that this is the compensation for renewable energy
credits or environmental attributes as I've defined them.
That's fairly common across the industry. When we enter
IRP-based contracts or wholesale contracts with wind developers
where we purchase the output of their facility, we often have a
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single price in the contract that says, We will pay you X
dollars per megawatt hour, and in exchange you will provide to
us the capacity, energy, environmental attributes, all of the
output of that facility.
So it's very uncommon for it to be a line item in
the contract, so it is possible for the capacity and energy
price to include the environmental attributes without it being
a line item in the contract.
Q. Well at the risk of repeating myself, I'll ask
you one more time, then I'll move on:
Do the Idaho avoided cost rates compensate QFs as
we speak for anything other than energy and capacity?
MR. SOLANDER: I'm going to object to this
question. This is at least the third time, and Mr. Clements
has answered at least three different ways.
MR. RICHARDSON: Madam Chairman, he's tried to
avoid the answer in three different ways.
COMMISSIONER SMITH: I think he answered it very
clearly and said that --
You better answer it.
THE WITNESS: Sure, I'll answer it. The
methodology does not include a specific line item that says,
Here is the compensation for environmental attributes. But,
again, that's a fairly common industry practice where we say,
We are purchasing the output of your facility at price X, and
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1 price X includes the entire output of facility capacity and
2 energy and environmental attributes and oftentimes other things
3 in the contract, just as there is more to energy than capacity
and energy.
Q. BY MR. RICHARDSON: Mr. Clements, in Idaho, do
avoided cost rates vary between a QF that produces RECs and a
QF that doesn't produce RECs?
A. No.
Q. In your testimony, you define "environmental
attribute" as a collection of the environmental and other
positive, nonenergy attributes of renewable generation, and
also it's the right to make a claim with respect to that
energy. Do you see that, familiar with that? I don't have a
cite but --
A. That sounds familiar, yes.
Q. Yeah. Where does PURPA or FERC regulation state
that the Utility automatically gains ownership of a QF's RECs?
A. PURPA does not specifically state that the
Utility receives ownership of the RECs. PURPA does not
specifically state that the ownership of the RECs remain with
the QFs.
My review with my legal counsel shows that that
is an issue that FERC has remanded to the states, and has made
it quite clear that that is a state issue, and it's up to the
state to determine ownership of RECs when it comes to PURPA
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contracts.
Q. So then you are aware that FERC has repeatedly
said that RECs are a creature of state law and outside the
scope of PURPA?
A. PURPA does not address REC ownership I think
would be my opinion, yes. And FERC has continually said that
it is a matter for states to determine ownership.
Q. Have you reviewed this Commission's Orders on REC
ownership?
A. I am unaware of any specific Order on REC
ownership, no, so I've not reviewed anything.
Q. So you didn't bother to review what this
Commission said about RECs before you got up here to tell this
Commission how to treat RECs?
MR. SOLANDER: Objection, Madam Chairman. I'm
going to object to the characterization of the question.
MR. RICHARDSON: I'll rephrase the question,
Madam Chair.
Q. BY MR. RICHARDSON: So you haven't reviewed any
of the Idaho PUC's rulings on REC ownership?
A. To my knowledge, there haven't been any direct
Idaho PUC Orders specifically related to REC ownership. If
there is a specific one you'd like me to look at, I would be
happy to do so.
Q. Well, there is one I would refer you to. It's
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Order No. 32294 where the Idaho Commission declared that the
Utility and the QF are free to voluntarily contract and
negotiate the sale and purchase of RECs should environmental
attributes be perceived by the contracting parties to have
value.
Would it surprise you that this Commission made a
statement like that?
A. Again, I'm not going to be surprised or not
surprised by what the Commission does.
Q. Because you just don't know?
A. Well, again, if I could answer the question,
Mr. Richardson, it has been the practice of the three Utilities
in this interim period or over the past several years where
there has been some degree of uncertainty or unknown parameters
around REC ownership, some of the Utilities have taken it upon
themselves to negotiate with the individual QF counterparties
regarding REC ownership, and there have been contracts that
have been executed that have dictated who owns the RECs. That
was done primarily so that there was certainty between both
parties as to REC ownership, because without that certainty,
neither party could do anything with the RECs. So in an
attempt to reach negotiation and finality with some of the QFs
in the past several years, the Utilities have taken it upon
themselves to negotiate the issue of REC ownership.
My testimony in this docket is that the
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Commission should adopt a permanent rule that if a QF elects to
sell under a PURPA contract, the Utility should keep the RECs.
MR. ANDREA: Madam Chair, if I could for just a
moment, Mr. Richardson has cited a prior Order of this
Commission. I'd ask that that entire Order be entered into the
record for completeness.
COMMISSIONER SMITH: The Commission can take
official notice of its own Orders, and I have a list now of
four of those.
MR. ANDREA: Thank you very much, Madam Chair.
Q. BY MR. RICHARDSON: Mr. Clements, is it a
prerequisite to be a QF that it produce RECs?
A. No, you can be a cogeneration facility and not
create RECs and still be a qualifying facility.
Q. On page 10, you state that absent Utility
ownership of all the differentiated resource's attributes, the
Utility is paying higher than its true avoided cost. Do you
see that?
A. Yes.
Q. One of the differentiated characteristics of a
cogeneration facility is steam, isn't it?
A. Yes, of the facility itself.
Q. So under your theory that, quote, Absent Utility
ownership of all of the differentiated resource's attributes,
the Utility is paying higher than its true avoided cost rate,
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then under your theory, PacifiCorp would own the steam that a
cogenerator produces, wouldn't it?
A. No, that would not be my position. Steam is not
typically one of the things that's included in the definition
of environmental attributes.
Q. Isn't steam included in the definition of a
cogeneration QF? That's one of the undifferentiated -- one of
the differentiated resource's attributes, is it not?
A. That is one of the attributes of the resource,
but --
Q. And your statement that "Absent Utility ownership
of all of the differentiated resource's attributes, the Utility
is paying higher than its true avoided cost," and you just
conceded that steam is one of the differentiated attributes of
a cogeneration facility, and the question is under your theory,
doesn't PacifiCorp or Rocky Mountain Power own the steam
produced by a cogenerator?
A. No, it does not, and let me explain why:
What I'm attempting to do in this portion of my
testimony is explain there's concepts called a null megawatt
hour, which basically means that if you strip the renewableness
from a megawatt hour of energy that's delivered, that megawatt
hour becomes what is known in the industry as a null --
N-U-L-L, that's how we phrase it -- which means that megawatt
hour of energy does not have any attributes in terms of
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renewableness or carbon or any of the environmental attributes
that I've described in my testimony. And so what I'm doing at
this point in my testimony is saying that if the renewable part
of the megawatt hour that is purchased by the Utility is
stripped off, then the Utility is simply purchasing a null
megawatt hour, and that's what I'm attempting to do at this
part of my testimony. And I would argue that the steam is not
part of the environmental attribute as I've defined in my
testimony.
Q. But it is part of the -- one of the
differentiated resource's attributes?
MR. SOLANDER: Objection: This is, again, the
third time he's asked the same question of Mr. Clements.
MR. RICHARDSON: I'll move on, Madam Chair.
Q. BY MR. RICHARDSON: Mr. Otto asked you about your
testimony on page 9, line 9, and I have a couple questions on
that as well:
At page 9, line 9, you state that any sale by a
QF of its RECs is defective. Do you see that?
A. Yes.
Q. In what way are QF sales of its RECs defective?
A. I think I've outlined that in my testimony here.
Would you like me to read that specifically?
Q. I'm wondering how you're using the word
"defective," if you could define that for me.
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A. Again, in one of my earlier answers, I stated it
really refers to the double-counting of RECs. There's an issue
of ownership and that's why there are counting procedures set
up in the West, primarily WREGIS, which ensures that
counterparties do not double-sell the RECs or double-count the
RECs. And so my argument in testimony is that unless you can
specifically claim or prove through a contractual means that
you are the owner of the REC, then a sale of that REC is
defective.
Q. Line 19 on the same page, you state that QFs
separately selling their RECs have engaged in the practice of
false advertising. Do you see that?
A. Ido.
Q. Pardon me?
A. Which line are you referring to?
Q. Line 19.
A. Yes.
Q. Now, my clients who are currently selling their
RECs don't advertise that fact. In fact, they prefer to make
such sales in private and under cover of a confidentiality
agreement. Who, exactly, is engaged in false advertising, in
your mind?
A. Well, again, this gets back to my issue of
double-counting of RECs. Unless you can prove through
contractual means that you are the owner of the REC, then you
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should not be selling it.
Q. Assume a QF is selling their RECs to a third
party in an arm's-length, private transaction. In that
situation, who is engaged in false advertising?
A. Well, if that QF can contractually demonstrate
that they are the owner of the REC, then that would not be what
I consider to be false advertising.
Q. And who is doing the advertising?
A. Again, by the fact that you're selling the REC
and representing that you own something, as long as you can
demonstrate that you own that through contractual means, I
would not consider that to be false advertising.
Q. One line down, you state that such activities are
fraudulent. Do you see that?
A. Yes.
Q. Are you aware that committing fraud in the state
of Idaho is a crime?
MR. SOLANDER: Objection.
MR. RICHARDSON: I'm asking what he means -- if
he knows what he's saying when he accuses people of committing
fraudulent activities.
COMMISSIONER SMITH: Well, I believe that's an
objection that needs to be sustained. Maybe you want to
rethink your question, Mr. Richardson.
Q. BY MR. RICHARDSON: In what way is the QF that
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I've recently described to you selling their RECs in an
arm's-length transaction committing fraud?
A. Again, if you're selling something that you
either do not own because it's not contractually certain that
you do own that, or that you are uncertain as to whether you
own it or not, then that, in my opinion, would be fraud.
Q. So when the Oregon PUC ordered that REC5 created
by QFs in the PURPA context belong to the QF, was the Oregon
PUC perpetrating a fraud on citizens of the state of Oregon?
A. Again, that's probably a legal opinion that I'm
not qualified to answer, but I will answer that in that
specific instance, the Oregon PUC determined that REC ownership
remains with the QF; just as in Wyoming, the Wyoming Commission
determined that REC ownership stays with the Utility. It's
defined, it's known, the owner of the REC is known by the state
that decided. And that's the intent of this proceeding here --
let me recant that. That's not the intent of this proceeding,
but my testimony is that this Commission determine REC
ownership as part of this proceeding.
Q. Thank you, Mr. Clements.
MR. RICHARDSON: Thank you for your indulgence,
Madam Chair. That's all I have.
COMMISSIONER SMITH: Thank you, Mr. Richardson.
Nothing from Mr. Miller.
Mr. Uda?
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CROSS-EXAMINATION
BY MR. UDA:
Q. To your knowledge, Mr. Clements, are all
renewable QFs capable of generating renewable energy credits?
A. That could be a very long answer. Again, it
depends on how you define "renewable energy credit." Renewable
energy credits are typically something that's defined by the
state, and in my experience, there are different types of
renewable energy credits.
For example, California, to meet the RPS for
California Utilities, they may have certain requirements about
what qualifies and what does not qualify. Typically that's
based on resource type: Wind, solar, whatever it may be. For
hydro, it may be online date, size of the hydro.
Nevada has slightly different rules for what
qualifies for their RPS.
And so the term "REC" is a general term that
means if it's a renewable project, it generates a REC. Now
whether that REC can be used to satisfy a Utility's RPS
requirement in its state, that is a separate question. So I
would say not all RECs are created equal to be the best answer
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there.
Q. Fair enough. Are you aware -- excuse me -- of
any renewable QFs that are waste coal plant facilities?
A. Again, it's dependent on how you define
"renewable." I am aware of some waste coal facilities that are
qualifying facilities, yes.
Q. But they're not cogeneration facilities.
Correct?
A. They're not cogeneration facilities, no.
And their RECs would not qualify under
California's RPS or Nevada's RPS, just to follow the line of
reasoning there.
Q. Sure.
MR. UDA: No more. Excuse me. I better not ask
any more.
COMMISSIONER SMITH: I think we have some water
way over there.
MR. UDA: I will go get some. Thank you,
Madam Chair.
COMMISSIONER SMITH: Mr. Williams.
MR. R. WILLIAMS: Just a couple of questions that
were spawned out of some prior exchanges.
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CROSS-EXAMINATION
BY MR. R. WILLIAMS:
Q. So, Mr. Clements, in your exchange with Mr. Otto,
you were asked and I believe your answer for justifying your
recommendation that the RECs will be owned by you, the
purchaser, was that the fact that the project is renewable is
the reason that it creates the REC, and, therefore, the
environmental attribute should follow the power. Did I
summarize that exchange correctly?
A. To a certain degree, with one clarification: The
fact that the renewable nature of a facility is what mandates
the purchase obligation on the Utility, it's logical that that
renewable attribute go along with the purchase obligation and
go to the Utility.
Q. And there's two forms of mandated purchase
obligations or two types of facilities, and one of those are
small power production facilities which are predominantly
renewable -- not always, but predominantly -- or at least they
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can be. Correct?
A. Again, "predominantly," I don't know if I'd use
that word, but oftentimes, yes, they are.
Q. Oftentimes. And then the other type that is
never the case would be cogeneration facilities. Correct?
A.

Cogeneration facilities typically do not generate
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case, couldn't this decision based at least on that argument
also determine that the value of the steam could go to the
Utility?
A. Yes, except I would phrase it slightly
differently. I wouldn't say it's the value of the steam. I
would say it's the value of the carbon offset of the combined
heating power facility.
And, again, this gets back to the issue of -- not
to expand too much upon this answer -- but we have to look at
avoided carbon costs or REC costs. And we're going down the
path of REC in the West, so I can see where in the future we
can say that the carbon offset value should go to the purchaser
as well, but that's not my position.
Q. But none of that has anything to do with the
steam produced by cogeneration. Correct? I mean, I want to
talk about steam; you want to talk about environmental
attributes.
A. Yeah, as I've defined "environmental attributes,"
steam is not one of them.
MR. R. WILLIAMS: No further questions.
COMMISSIONER SMITH: Mr. Arkoosh.
MR. ARKOOSH: Thank you.
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CROSS-EXAMINATION
BY MR. ARKOOSH:
Q. Mr. Clements, these RECs are what you would call
nonenergy attributes of renewable generation, is that correct,
in your testimony?
A. I don't recall using that exact phrase, but I say
that sounds correct, yes.
Q. And they can be separated from the energy
themselves and the energy itself and traded in a secondary
market. Is that correct?
A. It can be, yes.
Q. And they acquire a separate market value from the
energy?
A. It can, yes.
Q. And the ownership is governed by state law?
A. Ownership of the RECs, you're saying?
Q. Yes.
A. Is governed by state law?
Q. Yes.
A. That's a legal opinion I don't wish to weigh in
on.
Q. That's why we're here, isn't it, talking about
these RECs?
A. Yes. But in terms of what law governs ownership
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of the REC, I'm not prepared to provide an opinion on that.
Q.

Fair enough. Are they real or personal property?
MR. SOLANDER: Objection.
THE WITNESS: Again, legal opinion that I'm not
prepared to --
Q. BY MR. ARKOOSH: So that's an opinion for the
Commission, whether they're real or personal property, in your
view?
A. Again, not being an attorney, I leave it to the
purview of the Commission what they wish to decide or opine.
Q. So that's a legal opinion you won't render?
A. No.
Q. Thank you.
MR. ARKOOSH: And thank you, Madam Chair.
COMMISSIONER SMITH: Do we have questions from
the Commissioners?
COMMISSIONER REDFORD: No.
COMMISSIONER SMITH: No.
Do you have redirect?
MR. SOLANDER: I'm discussing. Could you give me
just one moment?
COMMISSIONER SMITH: Sure.
MR. SOLANDER: No questions, Madam Chair.
COMMISSIONER SMITH: Thank you.
And thank you for your help, Mr. Clements.
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THE WITNESS: Thank you.
(The witness left the stand.)
COMMISSIONER SMITH: We have reached the
fortuitous time for lunch. We will adjourn now for lunch and
be back at 1:15.
(Noon recess.)
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