20120828Volume VI.pdf

ORIr7 lN A
BEFORE THE IDAHO PUBLIC UTILITIES COMM27 p 5
UTL1TL5
IN THE MATTER OF THE COMMISSION'S
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
PLACE: Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE: August 8, 2012
VOLUME VI - Pages 920 - 1214
1Mr]
HEDRICK
COURT REPORTING
POST OFFICE BOX 578
BOISE, IDAHO 83701
208-336-9208
APPEARANCES
For the Staff:
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:
For Renewable Northwest
Project; Idaho Windfarms,
LLC; and Ridgeline Energy,
LLC:
KRISTINE A. SASSER, Esq.
Deputy Attorney General
472 West Washington
Boise, Idaho 83702
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
McDEVITT & MILLER, LLP
by DEAN J. MILLER, Esq.
420 West Bannock Street
Boise, Idaho 83702
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HEDRICK COURT REPORTING APPEARANCES
P. 0. BOX 578, BOISE, ID 83701
1 For Mountain Air Projects, UDA LAW FIRM, PC
LLC: by Michael J. Uda, Esq.
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7 West Sixth Avenue, Suite 4E
Helena, Montana 59601
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For Renewable Energy WILLIAMS BRADBURY, PC
4 Coalition and Dynamis by RONALD L. WILLIAMS, Esq.
Energy, LLC: 1015 West Hays Street
5 Boise, Idaho 83702
6 For Twin Falls Canal Company, CAPITOL LAW GROUP, PLLC
North Side Canal Company, by C. THOMAS ARKOOSH, Esq.
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Big Wood Canal Company, and 205 North Tenth Street,
American Falls Reservoir Fourth Floor
8 District No. 2: Boise, Idaho 83702
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HEDRICK COURT REPORTING APPEARANCES
P. 0. BOX 578, BOISE, ID 83701
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WITNESS
Don Reading
(Clearwater Paper, et al)
Cathleen McHugh
(Staff)
Rick Sterling
(Staff)
Ted Sorenson
(Renewable Energy Coalition)
Alan Hansten
(Twin Falls Canal Company,
et al)
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EXAMINATION BY
Mr. Richardson (Direct) 921
Prefiled Direct 923
Prefiled Rebuttal 992
Mr. Solander (Cross) 1009
Ms. Sasser (Cross) 1010
Mr. Andrea (Cross) 1018
Mr. Walker (Cross) 1032
Commissioner Smith 1042
Mr. Richardson (Redirect) 1044
Ms. Sasser (Direct) 1050
Prefiled Direct 1053
Prefiled Rebuttal 1066
Mr. Richardson (Cross) 1071
Ms. Sasser (Direct) 1075
Prefiled Direct 1077
Prefiled Rebuttal 1124
Mr. Solander (Cross) 1137
Mr. Andrea (Cross) 1139
Mr. Walker (Cross) 1140
Mr. Arkoosh (Cross) 1144
Mr. R. Williams (Cross) 1150
Mr. Richardson (Cross) 1154
Mr. Otto (Cross) 1180
Mr. Uda (Cross) 1188
Commissioner Smith 1196
Ms. Sasser (Redirect) 1199
Prefiled Direct 1205
Prefiled Direct 12111
HEDRICK COURT REPORTING INDEX
P. 0. BOX 578, BOISE, ID 83701
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EXH I BITS
NUMBER PAGE
For Staff:
301 Annual Energy Outlook 2012 Early Premark
Release, 2 pgs Admit 1070
302 Forecasted Natural Gas Prices Premark
Admit 1070
303 Comparison of Proposed SAR Methodology Premark
Rates Admit 1070
304 Comparison of Proposed IRP Methodology Premark
Rates Admit 1137
305 Calculation of Basis for Capacity Premark
Payments Admit 1070
306 Comparison of Proposed SAR Methodology Premark
Rates Admit 1070
For Mountain Air Projects, LLC:
2301 IPUC Case No. IPC-E-12-17 Comments of Mark 1193
the Commission Staff, 21 pgs Admit 1195
HEDRICK COURT REPORTING EXHIBITS
P. 0. BOX 578, BOISE, ID 83701
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BOISE, IDAHO, WEDNESDAY, AUGUST 8, 2012
COMMISSIONER SMITH: So, that takes me to
Dr. Reading unless Mr. Sorenson or Mr. Hansten are here and
wish to go now.
MR. RICHARDSON: Madam Chair, Clearwater Paper,
Exergy Development Group, and J. R. Simplot Company call
Dr. Reading to the stand.
COMMISSIONER SMITH: Thank you, Mr. Richardson.
MR. ARKOOSH: Could Mr. Schoenbeck be excused,
Madam Chair?
COMMISSIONER SMITH: If there is no objection,
we'll excuse Mr. Schoenbeck from the remainder of the
proceedings.
MR. ARKOOSH: Thank you, Commissioner.
MR. SOLANDER: Madam Chairman, if I can
interrupt? I neglected to excuse Mr. Clements yesterday when
he left the stand, and I'm wondering if he might be excused
from these proceedings as well.
COMMISSIONER SMITH: I don't know. If
Mr. Clements chooses to leave us, he's excused.
MR. SOLANDER: Just in case.
MS. SASSER: Run.
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HEDRICK COURT REPORTING COLLOQUY
P. 0. BOX 578, BOISE, ID 83701
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DON READING,
produced as a witness at the instance of the Clearwater Paper
Corporation, et al, being first duly sworn, was examined and
testified as follows:
DIRECT EXAMINATION
BY MR. RICHARDSON:
Q. So are you the same Dr. Reading who was recently
advised by your cardiac doctor to avoid stressful situations?
A. Yes.
MS. SASSER: I object.
COMMISSIONER SMITH: And I told him yesterday
that it was his lawyer that was actually doing the most damage.
MR. RICHARDSON: Guilty as charged, Madam Chair.
Q. BY MR. RICHARDSON: Are you -- Dr. Reading, are
you the same doctor --
First of all, state your name and your employer,
please.
A. Don C. Reading, R-E-A-D-I-N-G. And what was the
follow-up?
Q. Who are you employed by?
A. Ben Johnson Associates of Tallahassee, Florida.
Q. And are you the same Dr. Reading who caused
prepared -- prefiled direct and rebuttal testimony to be filed
I 921 I
HEDRICK COURT REPORTING READING (Di)
P. 0. BOX 578, BOISE, ID 83701 CPC, et al
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in this case?
A. Yes.
Q. And did you prepare or did you supervise the
preparation of Exhibits No. 501 through 507 (sic)?
A. Yes.
Q. And do you have any corrections or additions to
make to your prefiled testimony or exhibits?
A. The one correction that I found was on page 44,
line 9. I said Langley Gulch was 330 megawatts. I think
that's an old number, and it's 300 megawatts. So that would be
the only correction.
Q. With that correction, if I were to ask you the
questions you were asked in your prefiled testimony today,
would your answers be the same?
A. Yes, they would.
Q. Thank you, Dr. Reading.
MR. RICHARDSON: Madam Chair, I'll move that
Dr. Reading's prefiled direct and rebuttal testimony be spread
upon the record as if it were read in full.
COMMISSIONER SMITH: Seeing no objection, it is
so ordered.
(The following prefiled direct and
rebuttal testimony of Dr. Reading is spread upon the record.)
922
HEDRICK COURT REPORTING READING (Di)
P. 0. BOX 578, BOISE, ID 83701 CPC, et al

1 INTRODUCTION
2
3 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

4 A. My name is Don Reading and my business address is 6070 Hill Road, Boise, Idaho. I am
5 a principal with Ben Johnson Associates.
6 Q. HAVE YOU PREPARED AN EXHIBIT OUTLINING YOUR QUALIFICATIONS
7 AND BACKGROUND?

8 A. Yes. Exhibit No. 501 serves that purpose.

9 Q. On whose behalf are you testifying?

10 A. I have been retained by the Clearwater Paper Corporation, the J. R. Simplot Company
11 and Exergy Development Group of Idaho.
S 12 Q. WHAT ARE THE INTERESTS OF THOSE THREE ENTITIES IN THIS
13 DOCKET?
14

15 A. Clearwater Paper Corporation owns a large paper manufacturing facility near Lewiston,

16 Idaho. As part of its operations it generates electricity and sells that electricity to Avsita as a
17 qualifying facility (QF) under the Public Utility Regulatory Policies Act of 1978 (PURPA).
18 Cogenerating power at the Lewiston facility helps make it more profitable and stable. This is
19 important because Clearwater is Nez Perce County's single largest employer. Clearwater
20 directly employs about 1,300 people in Lewiston, almost seven percent of the total Nez Perce
21 County workforce. If it were to close, Nez Perce County's unemployment rate would double
22 from six and a half percent to almost fourteen percent. Clearwater is in the process of
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0 1 negotiating an extension of its existing contract with Avista. That contract expires next year. So
2 it is very interested in the outcome of this dock

3 The J. R. Simplot Company generates electricity at its Pocatello, Idaho phosphate
4 fertilizer facility. It sells its electricity to Idaho Power under a PURPA contract that is set to
5 expire next year. Like Clearwater in Lewiston, Simplot is a major employer in Pocatello. It
6 employs almost 350 people directly in the facility and another 200 at its Smokey Canyon Mine
7 All of the Smokey Canyon Mine's production is delivered to the Simplot Pocatello facility.
8 These five hundred and fifty jobs are made more secure and stable due to Simplot's ability to sell

9 its electricity to Idaho Power.

10 Exergy Development Group of Idaho is a successful renewable energy developer

11 throughout the country. Its main office is in Boise, Idaho. It is responsible for bringing
10 12 hundreds of megawatts of wind energy projects on line in Idaho over the past several years. It

13 developed the very first utility scale wind project in the state. Exergy is obviously very
14 interested in the outcome of this docket as its business model is, in part, based on PURPA.
15 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS CASE?
16 A. My testimony will address both to the avoided cost methodologies that I recommend
17 should be utilized by the Idaho Public Utilities Commission (Commission) to set standard and
18 non-standard avoided cost rates, as well as other QF issues. In Part 1 of my testimony, I will first
19 address why I believe the Commission should not make significant revisions to the surrogate
20 avoided resource (SAR) methodology for standard or published rates, and then I will address the
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1 Commission's implementation of IRP Methodology rates for projects above the eligibility cap
2 for published rates. In this section of my testimony I recommend to the Commission:

3 (1) That no deficit period be allowed and that QFs should receive capacity

4 payments for the full term of their contract;

5 (2) That if the IRP is going to be used for setting rates that it needs to be

6 litigated before the Commission through the hearing process;

7 (3) That input variables not be allowed to change between approved IRPs

8 with the exception of natural gas prices forecasts from a third party transparent

9 source; and

10 (4) That the single model run method proposed by Idaho Power be rejected.

11 In Part 2 of my testimony, I will address other issues related to PURPA and QF contracts.
12 I will explain why I recommend the Commission adopt or reaffirm the following QF policies:

13 (1) That liquidated damages provisions in QF contracts be tied to an estimate

14 of a utility's actual damages, and that QF contracts should likewise contain terms

15 protecting QFs in the event of a utility default;

16 (2) That QFs not be required to achieve on line status within 2 years of

17 signing a contract;

18 (3) That the standard term available for QF contracts remain at 20 years;

19 (4) That Idaho Power's economic curtailment tariff proposed for existing and

20 new QFs not be approved;
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1 (5) That a QF contracting tariff contain meaningful contract negotiation

2 guidelines and fair standard contracts for QFs choosing to sell their output on a

3 nonfirm basis and those choosing to sell pursuant to a legally enforceable

4 obligation;

5 (6) That QFs own environmental attributes in Idaho QF contracts because the

6 avoided cost rates do not compensation the QFs for more than the energy and

7 capacity alone; and

8 (7) That QFs will receive the same credit for transmission level upgrades

9 necessitated for their interconnection as non-QF generators and utility-owned

10 resources.
11

12 PART 1: AVOIDED COST RATE CALCULATIONS

13 I. PUBLISHED RATES
14 Q. DO YOU BELIEVE THERE ARE ANY COMPELLING REASONS FOR THE
15 COMMISSION TO CHANGE COURSE BY USING THE INTEGRATED RESOURCE
16 PLAN (IRP) METHODOLOGY INSTEAD OF THE SURROGATE AVOIDED
17 RESOURCE (SAR) FOR SMALLER PROJECTS?

18 A. No. The proxy or SAR method for determining a utility's avoided cost rates was the
19 method adopted by the Commission in 1980 when it first addressed its obligation to implement
20 the then new federal law. In my opinion, the SAR methodology has been a successful,
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0 1 transparent and effective method for estimating a utility's avoided cost rates.
2 Q. WHAT DID THE COMMISSION SAY ABOUT THE SAR METHODOLOGY
WHEN IT FIRST ADOPTED IT?
4 A. The Commission made it clear that it was laying a solid foundation for determining
avoided cost rates for the utilities it regulates by saying:
6 This Commission endorses the policy of having each utility pay its full avoided cost
7 when purchasing power from cogenerators and small power producers. Such a price will
8 bring about the equilibrium solution typical of a competitive market where the marginal
9 cost of all firms producing a like product is equal. Anything less will fail to bring about
10 the condition of a free, competitive market and will leave the utility, as the sole buyer, in
11 a position to dictate price as it sees fit.1
12
13 In this Order the Commission stressed that the price offered to QFs must be set at level that
14 would foster a competitive market or the utility would be left to dictate the price. The SAR or
15 proxy methodology was re-litigated in 1989 in Case No. U-1500-170. In that case the
16 Commission stated:
17 We find no avoided cost methodology presented in this case that is pragmatically
18 superior to the existing surrogate avoidable resource (SAR) method. Nor do we find a
19 method for determining the estimated time of load-resource balance that is superior to
20 using each specific utility's most recent load- resource plan (as incorporated in its Resource
21 Management Report) as the basis for a Commission determination establishing surrogate
22 utility specific resource plans following public hearing. Furthermore, we find that the most
23 appropriate surrogate resource for determining avoidable long term costs for utilities
24 operating in Idaho is a single hypothetical coal-fired steam plant with state of the art
25 emission controls. A surrogate resource is merely a means of estimating the value of energy
26 and capacity. The proxy unit need not actually be within a utility's resource plan.2
27
28 In that case none of the parties opposed the use of the proxy method and, indeed, all supported
IPUC Order 15746, Case No. P-300-12 (1980). 2 IPUC Order 22636, pp. 67-68, Case No. U-1500-179 (1989).
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1 the SAR methodology. Commission Staff in particular was helpful, as the Commission observed
2 in its order,

3 Staff admits that any method of administratively establishing avoided costs is "based, at
4 least in part, upon a fiction." In no small part, this is due to the vagaries of forecasting. One

5 of the advantages cited by Staff in the present SAR methodology is that it does not require a
6 detailed analysis of utility planned resources. Staff contends that a single Idaho avoided cost
7 rate would have the advantage of simplicity of application and administration. Although the

8 SAR method was described as consisting of seven steps, implementation of those steps
9 requires the Commission to establish at least 29 variables for computing avoided costs. The

10 set-point for most variables is selected from a range of reasonable values.
11

12 Staff recommends (1) maintaining the existing method of computing avoided costs,

13 (2) establishing a single avoided cost rate for all Idaho [sic.], and (3) establishing an

14 automatic method of periodically revisiting the variables.3
15
16 Numerous IPUC cases can be cited describing the rational for using the SAR methodology as a
17 reasonable and transparent method for determining avoided cost rates for the state's investor-

18 owned utilities.
19 Q. HAVE THERE BEEN ANY MAJOR CHANGES TO THE SAR METHODOLOGY
20 SINCE IT WAS FIRST ADOPTED BY THE COMMISSION IN 1980?
21 A. Yes. The one major change was in a 1993 case.4 In that case, the Commission concluded
22 that the avoidable resource should be changed to a natural gas-fired combined-cycle combustion

23 turbine rather that a coal-fired generating plant.
24 Q. IT HAS BEEN THIRTY TWO YEARS SINCE THE SAR WAS FIRST ADOPTED
Id..at pp. 1O-11.
IPUC Order 25926, Case Nos. IPC-E-93-28, PPL-E-93-5, UPL-E-93-7, UPL-E-93-3, PPL-E-93-3, WWP-
E-93-10 (1995).
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0 1 BY THE COMMISSION, HAVE CONDITIONS CHANGED SUCH THAT IT IS NO
2 LONGER RELEVANT FOR ESTIMATING AVOIDED COST RATES?
3 A. No. Quite the opposite, in fact. Idaho's energy picture has vacillated dramatically over
4 the past three decades. We have had periods of surplus and periods of deficit. We have
5 experienced periods of high load growth and low or even at times negative load growth. We
6 have had periods of high inflation and low inflation. We have had droughts and record water
7 years. The SAR methodology has been robust through all of those changes and has produced
8 avoided cost rates that have proven to be remarkably accurate in hindsight. Currently, I do not
9 see any conditions that would constitute a compelling reason to change Commission precedent at
10 this time by abandoning the SAR for setting avoided cost rates.
11 Q. WHAT POSITION HAVE THE UTILITIES TAKEN IN THIS DOCKET
•12 RELATIVE TO THE SAR METHODOLOGY?
13 A. In addition to my testimony discussing the utilities positions, I have also included
14 Exhibit No. 502, which includes several discovery responses regarding the avoided cost rates.
15 Idaho Power is an outlier in that it is the only utility recommending the SAR methodology be
16 abandoned. Both Rocky Mountain Power and Avista advocate maintaining the SAR
17 methodology for standard contracts while supporting a cap of 100 kw for wind and solar
18 projects to be eligible for published rates. According to the testimony of Rocky Mountain
19 Power's witness Kelcey Brown:
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1 The Company's position is that the current implementations of the SAR and IRP

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

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

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

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

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

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

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

9 increases since it does not take into consideration the value a specific QF project

10 would provide to each utility's unique power system and does not account for the

11 characteristics of each individual QF.5
12
13 I certainly agree with Ms. Brown in that the SAR methodology continues to provide a simple and
14 transparent means of pricing and that it helps to keep the transaction costs down. I would add,
15 however, that the benefit of reduced transaction costs inures to both the QF developer AND the

16 utility.
17 Q. IS THE SAR METHODOLOGY WIDELY ACCEPTED?

0 18 A. Yes, even Idaho Power witness William Hieronymus seems to agree. He cites a 1992
19 National Economic Research Associates (NERA) survey that he states might be 20 years old but,
20 "still is representative of administratively determined avoided methods in use today. ,6 This
21 survey indicated that 14 states, out of 49 surveyed used some form of the proxy method in
22 determining avoided cost rates for PURPA projects. This indicates the SAR method is widely
23 accepted as valid method for determining avoided cost rates.
24 Q. WOULD YOU DISCUSS THE THREE UTILITIES' RESOURCE ACQUISITION
Direct Testimony of Kelcey Brown, GNR-E-1 1-03, pp. 4-5. 6 Direct Testimony of Idaho Power Witness William Hieronymus, GNR-E- 11-03, pp. 59-60 (citing
Parmesano, Hethie and Bridgman, William, The Role and Nature of Marginal And Avoided Costs in Ratemaking; A
Survey, NERA (January 1992).
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0 1 HISTORY AS IT RELATES TO A COMBINED CYCLE COMBUSTION TURBINE?
2 A. Yes. Each of the three utilities have either recently added or will add a CCCT to their
3 generating system. It is clear that a CCCT is the resource of choice. Idaho Power is planning to
4 bring Langley Gulch on line in June 2012, with its next thermal unit being a combustion turbine in
5 2022 followed by a CCCT in 2025. Avista purchased the output of the Lancaster combined-cycle
6 generating station through a tolling agreement in 2007 and while the Company's next CCCT is not
7 planned until 2023 there is a combustion turbine in their preferred strategy in 2018.8 PacifiCorp has
8 a CCCI F Class scheduled to come on-line in 2014 and a CCCT H Class planned for 2016. For
9 the three investor-owned electric utilities in Idaho, as well as most of the rest of the country, a
10 CCCT is the resource of choice for base load plants for planning purposes and hence it remains the
11 reasonable choice for the proxy unit for the SAR.
12 Q. BEFORE YOU DISCUSS THE UTILITIES' RECOMMENDATIONS IN THIS
13 DOCKET WOULD YOU PLEASE DISCUSS SOME OF THE UNIQUE ASPECTS OF
14 AN ELECTRIC UTILITY'S AVOIDED OR MARGINAL COSTS AS ITS POWER
15 SYSTEM GROWS?
16 A. Yes. Due to required lead times, economies of scale, efficiency, etc., utilities tend to add
17 plant in relatively large increments. This means in actual practice, generation capacity is
18 periodically added in a "lumpy" fashion. Hence, at any given time, an actual system will have a
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-Idaho Power Company's 2011 Integrated Resource Plan, p. 7. 8 Avista Corporation's 2011 Integrated Resource Plan, p. viii.
PacifiCorp's 2011 Integrated Resource Plan, p. 8.
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1 bit more, or a bit less, than the optimal amount of generating capacity. Because generating
2 resources tend to be added to actual systems in relatively large MW increments (e.g. 100 MW or
3 more), and even if units are carefully sized to correspond to the system size, and expected rate of
4 load growth, it is too much to expect the mix of different types of generating plants to be
5 precisely optimum.

6 As Commissions around the county were struggling with the implementation of PURPA,
7 NERA produced a series of publications that became known as the "Grey Books." Although
8 these Grey Books were published just prior to the passage of PURPA, commissions and utilities
9 around the country used them in implementing PURPA because they set forth the theoretical
10 basis for quantifying a utility's marginal costs. These "Grey" books provided much of the

11 theoretical background that was used in establishing avoided cost rates by regulatory
1012 commissions. As explained by NERA in one of the "Grey Books", because capacity is added in

13 discrete blocks with long lead times, marginal costs fluctuate around the utilities long-run least
14 cost growth path.

15 Because of this fluctuation, in some years the short run operating costs may fall short of
16 what is needed to recover the total cost of building and operating a new generating unit - but in
17 other years, particularly just before the time when a new base load generating plant needs to be
18 added to the system, one would expect the marginal running costs of the system to be much
19 higher. This phenomenon is critical in defining avoided costs for a utility because of the way it
20 affects avoided or marginal costs in various time periods.
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0 1 Q. COULD YOU DESCRIBE WHAT YOU MEAN WHEN YOU STATE THAT
2 VARIOUS TIME PERIODS NEED TO BE CONSIDERED IN THE
3 DETERMINATION OF AVOIDED COST RATES?
4 Consideration of the time dimension in the consideration of marginal generating capacity
5 costs are outlined in the Topic 4 "Grey Book" referenced above. The publication discusses the
6 implications of using long-run and short-run marginal capacity costs
7 A. The long-run marginal generating capacity cost is the cost of the generating
8 unit that, in an optimal (least total cost generating mix) system, would be
9 added to accommodate increased peak-period demands. Depending upon the
10 utility's load duration curve and the natural resources available to the utility,
11 this unit will most likely be a combustion turbine, a pumped storage project, a
12 cycling (daily) fossil unit or an additional water wheel at an existing hydro
13 site.
14

15 B. The short-run marginal capacity cost will be the shortage cost for hours not

•
16 served. Theoretically, on an annual basis, if the expected shortage cost equals

17 or exceeds the cost of peaking capacity, system expansion will occur.
18

19 C. Due to the fact that capacity is acquired in discrete blocks and long lead times

20 are required, utilities will oscillate around the least total cost expansion curve.

21 Rather than follow the short-run costs in their oscillations around equilibrium,

22 it is recommended that, for marginal costinpurposes, the long-run mar2inal

23 costs gfzeneratin - capacity be used except in chronic cases of imbalance.

24 (emphasis added) °
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26 In practical terms what this means is, over time, a utility will in the normal course of
27 building plant to meet load almost always have surplus generating capacity. Because generation
28 plant will be added in chunks that will exceed its shorter-term load needs it will thus almost
10 NERA, How to Quantify Marginal Costs, Topic 4, Electric Utility Rate Design Study, pp. 2-3 (March
1977).
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0 1 always have a capacity surplus. Unless QFs are credited for long-run capacity costs they will
2 never by compensated on an equal basis relative to what the utilities receive in rates to build
3 plant.
4 Q. YOU HAVE STATED THE NEED FOR THE TIME DIMENSION TO BE
5 TAKEN INTO ACCOUNT IN THE DETERMINATION OF AVOIDED CAPACITY
6 RATES. IS THE SAME TRUE FOR DETERMINING AVOIDED ENERGY COSTS?
7 A. Yes. That same NERA Topic 4 "Grey Book" explains why the calculation of marginal
8 energy costs should also take into account the oscillations around a utility's least cost planning
9 path.
10 In the case of systems oscillating around an optimal generating mix equilibrium, it
11 is desirable to analyze marginal energy costs over a full cycle of oscillation,
12 usually five to ten years into the future. (emphasis added)"
.13 14 Idaho Power's proposed method for determining avoided energy costs (discussed in more detail
15 below) uses a very short-run hourly marginal cost calculation.
16 Q. Are there times when the incremental cost calculated with Idaho Power's
17 proposed methodology goes to zero?
18 A. Yes, and this is not unrealistic. Considering the minimum load levels
19 established for the thermal generating resources, and the amount of non-
20 dispatchable QF generation on Idaho Power's system, there may be hours during
21 low load periods when Idaho Power's avoidable incremental costs are zero. In
22 fact, there could be times when Idaho Power's avoided incremental costs would
23 be negative. 12
11 Id.,p.4.
12 Direct Testimony of Idaho Power Witness Karl Bokenkamp, GNR-E-1 1-03, P. 14.
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0 1 Including these "avoidable incremental costs" as part of the calculation of avoided energy cost,
2 as in the case of avoided capacity costs described above, does not put the QF on an equal cost
footing with the utility's own resources. In any given hour the utility is incurring energy costs to
4 produce power to serve loads that are being passed on to customers. When the utility requests a
5 certificate from the Commission to build plant it includes its expected fuel costs for the plant at
6 an assumed capacity factor. What the utility does not do is add the plant to its resource stack and
7 then ask for recovery based on the highest cost resource it may be replacing on an hourly basis.
8 Q. EACH OF THE UTILITIES IN THIS DOCKET ARE ADVOCATING THAT QFs
9 SHOULD NOT BE ELIGIBLE FOR CAPACITY PAYMENTS WHEN THE UTILITY'S
10 FORECASTS DETERMINE THAT CAPACITY IS NOT NEEDED. GIVEN YOUR
11 EXPLANATION OF THE "LUMPY" NATURE OF A UTILITY'S INVESTMENTS, DO
0 12 YOU HAVE A POSITION ON THAT ISSUE?
13 A. Yes. As I have explained above, a utility will add plant in increments that will exceed its
14 short term needs to serve load. Therefore, unless due to some unforeseen factor or under-
15 forecasting, a utility will almost always be surplus for the next few years. As noted in Avista
16 witness Clint Kalich' s Direct Testimony, the Commission explicitly dealt with first deficit year
17 or surplus period issue in Order 29124. In that Order the Commission concluded:
18 The continued importance of a first deficit year in avoided cost
19 calculations has to be weighed against the improbability of settling on a surplus
20 period in which anyone has confidence. Utilities have had the opportunity to
21 instill confidence in the first deficit year but in failing to update for changes in
22 load/resource balance have compromised the public confidence in the
23 reasonableness of its continued use. It is a factor in avoided cost calculation, the
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I Commission finds, that needs to be taken into account only to the extent

2 practicable. Reference 18 C.F.R. 292.304(e). The record supports a finding that

3 continued use of the first deficit year is administratively burdensome and no

4 longer practicable .....We find it appropriate to create an avoided cost that

5 contains the full value for both energy and capacity. 13
6
7 The Commission also noted in that same Order that one of the intervenors, Plummer Forest

8 Products, offered a metaphor for a utility's surplus period:
9 It was also suggested by Plummer that it poses a "Catch 22" dilemma - i.e., a

10 utility only has to purchase if it's deficit; however, a utility can extend its surplus

11 by constructing its own resources, so a utility is never deficit and never has to

12 purchase. 14
13
14 A "Catch 22" dilemma is an apt phrase for the trap that a QF faces when it is denied capacity
15 payments when a utility claims it is in surplus. As pointed out above the denial of capacity
16 payments during a period of claimed surplus does not put a QF facility and a company owned
17 generating plant on an equal footing.
18 Q. IN HIS DIRECT TESTIMONY AVISTA'S WITNESS KALICH INDICATES
19 THINGS ARE DIFFERENT NOW THAN THEY WERE IN 2002 WHEN THE
20 COMMISSION ISSUED ORDER NO 29124 AND GOES ON TO REBUT THE NINE
21 REASONS OUTLINED BY STAFF FOR THE ELIMINATION OF THE DEFICIT
22 PERIOD. DO YOU HAVE ANY COMMENTS REGARDING MR. KALICH'S
23 TESTIMONY?
24 A. I will not comment point for point on his rebuttal points but, taken as a whole, his
13 IPUC Order No. 29124, GNR-E-02-01 (2002).
14 Id..
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1 arguments do not justify eliminating capacity payments to a QF during surplus periods. I will
2 focus on three points; first his assumed definition of "true avoided cost," second the difference
3 between "surplus" energy rates and rates identified in an SAR, and third that the utilities' IRPs
4 are subject to "significant oversight."
5 Mr. Kalich addresses the point that utilities are likely to be surplus in the near term (point
6 7). Mr. Kalich States:
7 The seventh concern was that utilities tend to be surplus in the near term,
8 and that avoided cost rates should not provide incentives for a utility to increase
9 its length to avoid having to purchase PURPA power. It is often true that utilities
10 are surplus in early years; being so is an essential part of providing reliable utility
11 service. It also is true that QF developers would be affected by these surpluses
12 were they to receive lower early-year payments during surplus years. But this
13 effect is a reflection of true avoided costs. (emphasis added)15
14
• 15 Given the discussion above about "lumpy" utility investment, I certainly agree with the first part
16 of the above statement that utilities tend to be surplus in the near term. However, also as
17 discussed previously, I strongly disagree that QFs receiving lower early-year payments are a
18 reflection of "true avoided costs." Avista apparently believes "true avoided costs" means QFs
19 seldom are compensated for capacity payments for their facilities in the early years while the
20 Company's own generation plant receive recovery of full capacity for the full term of the plant
21 life.
22 Q. THE SIXTH CONCERN EXPRESSED BY STAFF WAS THAT THE
23 DIFFERENCE BETWEEN PURPA RATES AND "SURPLUS" ENERGY HAD
15 Direct Testimony of Avista Witness Clint Kalich, GNR-E- 11-03, pp. 13-14.
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0 1 NARROWED AND HENCE THERE WAS LESS JUSTIFICATION FOR
2 DISTINQUISHING THE DIFFERENCE. DO YOU AGREE WITH THAT
3 CHARACTERIZATION?
4 A. Yes and no. At this time there are significant differences between SAR set rates and the
5 surplus energy rates. However over the past 30 years that PURPA rates have been in place in
6 Idaho there have been periods where market rates have been both less than and greater than SAR
7 set rates. At this time, the price of natural gas tends to drive electric rates. While current gas
8 rates are very low, natural gas rates have tended to be extremely volatile over time and, as
9 pointed out above, avoided cost rates should reflect the long-run marginal costs for a utility.
10 Mr. Kalich believes this concern is made moot if his recommendation for bifurcating
11 energy and capacity payments to a QF is adopted. He proposes capacity payments for a QF
12 calculated on a per-MW "on-peak contribution" basis. Mr. Kalich's proposal seems to disregard
13 the FERC requirement that avoided cost rates must consider the individual and aggregate value
14 of energy and capacity from the fleet of qualifying facilities on the utility's system. 16
15 Q. MR KALICH INDICATES THE FIRST FOUR CONCERNS OF STAFF ARE NO
16 LONGER VALID BECAUSE THE UTILITIES EACH FILE AN IRP EVERY TWO
17 YEARS THAT ARE "SUBJECT TO SIGNIFICANT OVERSIGHT." DO YOU AGREE
18 THAT THE REQUIRED FILING OF AN IRP EVERY TWO YERS IS SUFFICIENT
19 REASON TO ALLEVIATE STAFF'S CONCERNS?
16 18 C.F.R. § 292.304(e)(vi).
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. 1 A. I would agree if the utilities IRP's were, in fact, "subject to significant oversight" in their
2 development and submission. The Idaho Commission only accepts each utility's IRP for filing;
3 it does not approve the utility's conclusions. The following Commission statement is taken from

4 Idaho Power's 2011 IRP. It is typical for all Idaho IOUs:

5 Based on our review, we find it reasonable to accept for filing and to

6 acknowledge Idaho Power's 2011 Electric Integrated Resource Plan. Our

7 acceptance of the 2011 IRP should not be interpreted as an endorsement of any

8 particular element of the Plan, nor does it constitute approval of any resource

9 acquisition contained in the Plan. 17
10

11 It is significant that the Commission states it's acceptance for filing of the IRP does not
12 constitute approval of any resource acquisition nor even an endorsement of any particular

13 element in the plan. It is true the utilities have instituted a public process in the development of
14 their IRPs along with forming consumer advisory groups. However, an IRP contains a large
15 number of very complex and technical aspects that lay advisory groups do not have the time or

16 expertise to thoroughly critique.
17 Q. DR. READING, WHAT DO YOU RECOMMEND IN THE FUTURE FOR
18 DEVELOPMENT OF IRPs?
19 A. IRPs are becoming increasingly relied upon for a wide number of important regulatory
20 issues. These uses include justifying adding resources, establishing avoided costs, determining

21 periods of deficit and surplus, projecting load growth, and measuring cost effective DSM, etc.
17 IPUC Order No. 32425, Case No. IPC-E-1 1-11 (2011).
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1 Given the importance of the IRP in justifying utility expenditures and its ultimate impact on
2 customer rates it is essential that the IRP be subject greater scrutiny and subjected to a litigated
3 hearing and ultimately approval by the Commission. Only after the IRP is subjected to thorough
4 examination should its various conclusions be accepted for rate setting purposes.
5 Q. HOW DOES AVISTA RECOMMEND CALCULATION OF CAPACITY COSTS?
6 A. As discussed in the last section, Avista' s Mr. Kalich is recommending bifurcating energy
7 and capacity payments to QFs. He proposes capacity payments for a QF be calculated on a per-
8 MW "on-peak contribution" basis. This is accomplished by converting the SAR per MWh
9 payment level to a total annual capacity payment that is divided by the expected annual capacity
10 factor. For PURPA projects eligible for published avoided cost rates, rather than using capacity
11 based on the SAR, he advocates calculating capacity payments based on the nature of the project.
0 12 In addition he recommends these separate capacity amounts based on the type of project be
13 calculated on a per MW basis and then "translated" to a dollars per MWh that is added to the per
14 MWh energy rate to determine avoided cost. He also asks that once the SAR capacity payment is
15 calculated it serve as a cap on total payments for any given year to prevent a QF from
16 underestimating its energy output.
17 Q. DO YOU AGREE WITH THESE CHANGES AVISTA IS ADVOCATING FOR
18 THE CALCULATION OF CAPACITY PAYMENT FOR QFs ELIGIBLE FOR
19 PUBLISHED RATES?
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1 A. The process adds unneeded and unnecessary complexity to the calculation of avoided
2 costs for published rates. As pointed out above, especially for smaller QFs eligible for published
3 rates the computing of avoided costs should be as simple and straight forward as possible. It
4 should be transparent and understandable. In my opinion, he is solving problems that do not
5 exist.
6 Q. DO YOU AGREE WITH ANY OF MR. KALICH'S RECOMMENDATIONS?
7 A. I agree with his recommendation that the Commission should use the regularly updated
8 gas forecast generated by the Energy Information Administration (EIA) in its Annual Outlook
9 Report as the forecast by which the Commission updates the published gas SAR avoided cost
10 rates. 18 The Commission currently uses the irregularly published gas forecast generated by the
11 Northwest Power and Conservation Council.
0 12 Although the Northwest Power and Conservation Council's forecast can provide a stable
13 rate for QFs, it can be difficult for QFs to know when to expect the rates to go up or down. I
14 believe all parties, including QFs, the Commission, and the utilities, could benefit from a
15 predictable rate change at a predetermined date each year occurring within a reasonable time
16 period of the regularly released EIA Outlook Report. The full report appears to be released in
17 the spring. I recommend that the Commission clearly state that the rates each year will be
18 updated on a specific date each year, such as on June 1, whether the rates are going up or down.
19 I believe this recommendation addresses the utilities' concern that the existing gas price updates
18 Direct Testimony of Avista Witness Clint Kalich, GNR-E-1l-03, p. 34.
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1 are too infrequent, and would provide parity in the timing of the rate increases and decreases.
2 II. NON-STANDARD RATES FOR QFs ABOVE THE ELIGIBILITY CAP
3 Q. THE THREE IDAHO IOUs IN THIS DOCKET HAVE FILED WHAT THEY
4 CHARACTERIZE AS THE COMMISSION APPROVED "IRIP METHODOLOGY" FOR
5 THE DETERMINATOIN OF AVOIDED COST RATES. WOULD YOU PLEASE
6 DISCUSS THE APPROACH EACH UTILITY HAS RECOMMENDED TO THE
7 COMMISSION FOR APROVAL?
8 A. I examined the three proposals and compared them against the Commission Staffs "IRP
9 Methodology" for determining a utility's avoided cost for PURPA projects in Idaho that the
10 Commission approved in Case No. IPC-E-95-09. The methods put forth by the utilities vary
11 significantly. RMP follows the approved methodology fairly closely. Idaho Power, however,
0 12 takes an entirely different approach.
13 Q. WOULD YOU PLEASE EXPLAIN IN MORE DETAIL WHAT YOU MEAN
14 WHEN YOU STATE THAT THE APPROVED IRP METHODOLOGY IS NOT BEING
15 FOLLOWD BY ALL OF THE UTILITIES?
16 A. Before analyzing each of the utilities' proposals, an examination of the generally
17 accepted approaches to calculating avoided costs needs to be considered. Idaho Power witness
18 William Hieronymus in this direct testimony reviews what he refers to as the taxonomy of
19 administrative methods for setting avoided costs as set forth in a report by the Edison Electric
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1 Institute (EEl) that examined the setting of avoided costs. 19 The paper was prepared by the
2 Brattle Group. The three methods found in the EEl paper also match those found in the survey
3 by NERA discussed above.
4 Q. COULD YOU PLEASE BRIEFLY DESCRIBE THESE THREE METHODS
5 THAT HAVE BEEN USED BY REGULATORY COMMISSIONS IN THE
6 DETERMINATION OF AVOIDED COST RATES FOR PURPA PROJECTS?
7 A. State public utility commissions have used three basic approaches for determining
8 avoided costs since the enactment of PURPA in 1978. Various states have employed various
9 incarnations of these three basic approaches, as pointed out in the NERA survey for finding
10 avoided costs for utilities under their jurisdiction. The three methods are: 1) the Peaker Method,
11 2) the Proxy Method, and the 3) Differential Revenue Requirement Method.
10 12 Q. WOULD YOU PLEASE DESCRIBE THE PEAKER METHOD?
13 A. Yes. When using the Peaker Method, the utility's power supply model is run with and
14 without the given facility, at zero cost, to produce variable costs. Then, the capital costs of a
15 peaking unit on a MWh basis is added to variable costs to find a utility's avoided costs.
16 Q. WHAT IS THE PROXY METHOD?
17 A. Under the Proxy Method (which is currently used in Idaho for published rates), the
18 capital costs of the proxy unit are included, along with operation and maintenance expenses
19 including fuel, as part of the calculations to find the utility's avoided cost. The assumption is
19 Edison Electric Institute, PURPA: Making the Sequel Better than the Original (December 2006).
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0 1 these calculated costs are a "proxy" for what the utility would incur to build the unit and
2 therefore are a reasonable estimate of its avoided cost.
3 Q. THE THIRD APPROACH YOU MENTIONED IS THE DIFFERENTIAL
4 REVENUE REQUIREMENT METHOD. WOULD YOU PLEASE EXPLAIN THIS
5 METHOD?
6 A. Yes. The Differential Revenue Requirement Method calculates the utility's total
7 generation costs (or revenue requirement) with, and without, the proposed facility. This method
8 first uses an expansion plan model to generate expansion plans with and without the proposed
9 facility. The method then uses the two different expansion plans as inputs to a financial planning
10 model to produce the utility's revenue requirement with and without the proposed facility's
11 output provided as free energy. That financial model would include items such as interest costs,
0 12 taxes, allowed rate of return on the change in rate base and capital and other "rate case" inputs
13 for the facility. The difference in the present value of the revenue requirement is the avoided
14 revenue requirement component and is, in theory, the utility's full avoided cost, including
15 avoided energy and capacity costs, as well as taxes and other cost factors.
16 The Commission accepted the Differential Revenue Requirement Method for finding
17 avoided cost rates for QFs larger than 1 MW in Case No. IPC-E-95-9. The Commission
18 approved a stipulation in that case that was signed by the three utilities, Commission Staff, and
19 Rosebud Enterprises, Inc. Other parties in that docket chose not to sign the stipulation, but they
20 did not oppose the methodology. Attached to Commission Staff witness Sterling's Direct
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1 Testimony filed in that case is Exhibit 101 that contains Staff's proposed avoided cost
2 methodology that was accepted by the Commission. This is the approach that is being commonly
3 referred to as the "IRP Methodology" for Idaho utilities.
4 Q. WHY DO YOU SAY THE DIFFERENTIAL REVENUE REQUIREMENT
5 METHOD IS ESSENTIALLY THE METHOD APPROVED BY THE COMMISSION IN
6 CASE NO. IPC-E-95-09?
7 A. The essence of Staff's methodology is employing the Differential Revenue Requirement
8 Method described above comparing the present value of the revenue requirements (PVRR) of the
9 base case with one that includes the utility's system including the QF. Items 6 and 7 of the

10 Stipulation state:

11 6. Finally, the present value of the QF project avoided cost is calculated by

.
12 subtracting the PVRR of the modified plan, with the costs of the QF set

13 to zero, from the PVRR of the base case resource plan
14

15 7. Rates for capacity and energy from the QF project can then be developed for

16 which, on a present value basis, the expected payments to the QF are equal to the

17 project's avoided cost over the life of the contract. 20
18
19 Note that item 7 states that the avoided cost rate for a QF is found by using both capacity and
20 energy. The end result is that Idaho has two methods for calculating avoided costs, the Proxy
21 method for smaller projects, and the Differential Revenue Requirement Method for larger
22 projects
20 Direct Testimony of Commission Staff Witness Rick Sterling, IPUC Case No. IPC-E-95-09, Exhibit 101, p.
8.
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0 1 Q. COULD YOU REVIEW THE "IRP METHOD" PROPOSED BY EACH IOU IN
2 THIS DOCKET?

3 A. Rocky Mountain Power appears to follow differential revenue requirement method
4 proposed by Staff and approved by the Commission. RMP Company witness Kelcey Brown, in
5 describing that Company's approach, first reviews the seven steps outlined in Staff's "IRP
6 Methodology" and then outlines how the Company follows each of those steps. 21 For the energy
7 component of avoided costs, the Company uses a "GRID" model for two simulations. One using
8 the preferred portfolio, and the second for the QF at no cost that finds the PVRR and then
9 calculates the difference between the two.
10 Q. HOW DOES RMP FIND THE CAPACITY COMPONENT OF AVOIDED
11 COSTS?

1012 A. To calculate the capacity component of avoided costs, Rocky Mountain Power first
13 determines the level of deferrable capacity measured by the next deferrable CCCT found in its
14 latest IRP, plus the impact of capacity from the requesting QF. Also, when a QF makes a request
15 for avoided cost prices the Company updates the GRID with its latest forecasts for a set of
16 variables they assume have changed since the IRP was filed. According to Ms. Brown:
17 The Company updates the GRID model based on the most recently available
18 information each time a QF requests avoided cost pricing. This includes updates
19 related to new contracts, fuel prices, forward price curves, load forecasts and
20 other assumptions. However, the underlying IRP preferred portfolio does not
21 change and is consistent with the most recently filed IRP.22
21 Direct Testimony of Rocky Mountain Power Witness Kelcey Brown, GNR-E-11-03, pp. 7-10.
22 Direct Testimony of Commission Staff Witness Rick Sterling, IPUC Case No. IPC-E-95-09, p. 13.
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•1
2 This means the price offered to the QF is calculated on a different basis than what the
3 utility used in the development of their preferred portfolio in their IRP -- which is used to justify
4 the construction of their own resources among other things. In addition, this means the QF
5 requesting a price has the burden of vetting RMP's latest view of loads, fuel prices, and other
6 variables. These "updated" variables have not had even a cursory review by the Commission or
7 stakeholders as have these inputs found in the IRP. In addition, because the outputs of the GRID
8 model run for QFs are being subtracted from the base case with different underlying input
9 assumptions, the results are confounded by whatever changes in these variables the utility
10 assumes have occurred. As discussed above, the IRP's need greater scrutiny if they are to be
11 used for the calculation of avoided cost rates, these unilateral interim adjustments are a step
12 further away from the vetting process and should not be allowed.
13 Q. DR. READING, WOULD YOU PLEASE COMMENT ON AVISTA'S APROACH
14 TO THE CALCULATION OF AVOIDED COSTS?
15 A. According to Avista's response to a production request, under the IRP Methodology,
16 assumptions are first reviewed and updated where appropriate (e.g., natural gas, loads and
17 resources). Where assumptions affecting the wholesale marketplace have changed (e.g., natural
18 gas prices) the AURORA IRP model is re-run and Avista's PRiSM model is updated with the
19 new wholesale market data (i.e., value of the new generation resource options). The Company
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1 then produces two new PRiSM runs to determine capacity and energy values. In the first new
2 PRISM run, the capacity component of the QF resource is added to the load and resource
3 tabulation (L&R). The difference between the two economic values (i.e., revenue requirement
4 between the pre-QF PRiSM run and PRISM run containing the QF capacity) determines the
5 avoided capacity value available for the QF contract. A second PRiSM run is then performed
6 where both the expected capacity and energy contributions of the QF resource are added to loads
7 and resources. The difference between the first PRISM run and the second PRISM run
8 determines the energy payments available to the QF contract.
9 This procedure is somewhat similar to that used by RMP. Loads, natural gas prices, etc.
10 are updated, the QF capacity is added to the resources of the utility and the difference between
11 two PRISM runs, one with and one without the QF, is calculated to find the avoided cost of
12 energy. As discussed above the input variables that are updated from the IRP by the utility are
13 not subject to any regulatory or stakeholder review and therefore should not be allowed to be
14 used in the calculation of avoided energy costs.
15 Q. AVISTA IS RECOMMENDING ONE OF THOSE INPUT VARIABLES,
16 NATURAL GAS PRICE, BE UPDATED ANNUALLY FROM RATES PUBLISHED BY
17 THE ENERGY INFORMATION ADMINSTRATION (EIA) IN ITS ANNUAL ENERGY
18 REVIEW. DO YOU AGREE WITH THIS RECOMMENDATION?
19 A. Yes, because this gas forecast is published by a neutral source on an annual basis and
20 because it is assessable and transparent for all parties. Therefore, for this input from this source it
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1 is reasonable to change natural gas prices between the utilities' IRPs. This is consistent with my
2 agreement discussed above with Mr. Kalich's recommendation to use the EIA forecast to
3 annually update published rates in the SAR. Other third party transparent sources for natural gas
4 prices could also be acceptable, so long as a predetermined date is set by the Commission for the
5 update to allow for parity in input changes that will result in rate increases and rate decreases.
6 Q. COULD YOU NOW DESCRIBE HOW IDAHO POWER IMPLEMENTS THE
7 "IRP METHOD" APPROACH APPROVED BY THE COMMISSION?

8 A. Yes. Idaho Power recommends abandoning the Commission approved method entirely.
9 It is recommending a peaker method (although it is still being called a modified "IRP
10 Methodology"). The Company is recommending the use of a SCCT rather than a CCCT. In
11 addition, it has abandoned the two model run approach (one with and one without the QF
10 12 requesting avoided cost pricing), for a single model run method that attempts to replicate the
13 Company's operation of its resource stack during each hour for all hours of the QFs contract
14 term.
15 Q. COULD YOU PLEASE EXPLAIN IN GREATER DETAIL HOW IDAHO
16 POWER PROPOSES TO DETERMINE THE AVOIDED COST OF ENERGY THAT
17 WILL BE OFFERED TO A QF?

18 A. Idaho Power is proposing a single run of the AROURA model that calculates avoided
19 energy costs equal to the cost of the Company's most expensive unit forecasted to be on-line for
20 each hour of the year for the contract term. As discussed in the last section, this is estimating
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I avoided cost on a ygry short-run hourly basis. According to the direct testimony of Company
2 witness Karl Bokenkamp:

3 Once the highest displaceable incremental cost is identified for a given hour, any amount

4 of displacement available from that resource (generator, longer-term firm purchase or

5 market purchase) sets the incremental cost for that hour regardless of the volume actually

6 available to be displaceable; e. g., if there are no purchases, and all thermal plants are

7 either off or at their minimums except for one Bridger unit which is at 10 MW above

8 minimum and its incremental cost is $17 /MWb even if the "new" QF that the analysis is

9 being run for is expected to produce 20 MW during that hour. This simplification may

10 introduce some error, but it will always be in favor of the QF since Idaho Power begins

11 with the highest incremental cost resource that is displaceable to set the avoided cost for

12 any hour. 23
13
14 However Idaho Power makes another "simplification." This "simplification" of the model run
15 assumes that each of the Company's thermal units has a heat rate equal to its full load operation:

16 During many hours of the year, Idaho Power's highest displaceable incremental cost will

17 be set by one of its thermal resources. And because a thermal plant's heat rate changes

18 with load, the incremental costs also change with load. However, to simplify the analysis,

19 Idaho Power proposes use of the following assumptions:
20

21 1. Each thermal unit is assigned one incremental cost, which will be based on full load

22 operation, which applies all year long regardless of the loading level determined in the

23 AURORA analysis[.] (emphasis added)24
24
25 The problem with this approach, as Mr. Bokenkamp points out, is that heat rates change as
26 thermal units are ramped up and down. As the generating unit is backed down to follow load its
27 heat rate goes up and its efficiency goes down. Therefore, the cost per MWh of output goes up.
28 Assuming all units in the Company's resource stack are operating at full load, reduces the
23 Direct Testimony of Idaho Power Witness Karl Bokenkamp, GNR-E- 11-03, p. 25.
24 Id,p.24.
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1 avoided cost assumption from how the Company actually operates. According to a Response to a
2 Production Request the $/MWh difference in incremental energy cost between maximum and
3 minimum load for a unit can be as much as 20%.25 This process results in an unrealistically low
4 avoided cost rate. In addition, the incremental cost for each thermal unit is updated each year
5 based on the fuel forecasts which, as discussed above, are not subject to any analysis other than
6 the Company's own estimates.
7 Q. WHAT CONCLUSIONS CAN YOU DRAW FROM YOUR ANALYSIS OF
8 IDAHO POWER'S APPROACH TO CALCULATING AVOIDED ENERGY COSTS
9 THAT WILL BE OFFERED TO A QF?
10 A. Idaho Power's approach is fatally flawed. As pointed out above, the approach incorrectly
11 assumes avoided costs should be based on a very short-run hourly basis. The Company also
1012 makes additional "simplifying" assumptions that lower the price that will be offered to a QF. It
13 certainly does not put a PURPA project and the Company's own resources on an equal cost
14 basis. The Company does not, when it wants to build one of its own resources, add that resource
15 to its AURORA model runs, and then ask the Commission for recovery based only on the value
16 of the highest cost resource in the stack in every given hour over the life of the plant. What the
17 Company does is estimate the costs of the resource at a given capacity factor -- which closely
18 approximates the SAR method currently in place.
25 Idaho Power' Attachment to Response to Exergy's Second Production Request No. 33(b), contained in
Exhibit No. 502.
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1 Q. HOW DOES IDAHO POWER RECOMMEND CAPACITY COSTS BE
2 CALCULATED?
A. According to the testimony of the Company's witness:
4 The proposed modifications to the IRP-based methodology produce a
5 lower avoided cost of energy for each project. This is expected because the
6 proposed modifications (which are based on identifying the incremental costs to
7 the utility for energy or capacity which, but for the QF purchase, the utility would
8 generate itself or purchase) produce an avoided cost that is based on the
9 incremental cost avoided by displacing one of Idaho Power's thermal generating
10 resources, or avoiding a market purchase. This is in contrast to the current
11 implementation of the IRP methodology which uses the QF output to support
12 market sales or displace purchases which results in a market-based valuation as
13 opposed to a valuation based upon the definition of avoided cost.
14 The proposed modification to the type of resource used in the avoided cost
15 of capacity calculation results in an avoided cost of capacity that is about 55
16 percent of that produced by using a CCCT. This is also expected because the
17 capital costs of a SCCT are quite a bit less than the capital costs of a CCCT. The
18 total investment costs for a SCCT and CCCT as identified in Idaho Power's 2011
.
19 IRP are $790/KW and $1,380/kW, respectively. 26
20
21 As pointed out above, the Company is proposing to use the "peaker method" in the calculation of
22 avoided costs to be offered to QFs. It should be pointed out once a utility is allowed to put one of
23 their own resources in rate base it will receive full recovery of the capital cost irrespective of
24 whether or not the unit runs. The Company also expresses concerns that ratepayers will get stuck
25 with a PURPA project for a 20 year period without acknowledging that once one of their own
26 Direct Testimony of Idaho Power Witness Karl Bokenkamp, GNR-E- 11-03, p. 32.
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1 plants is placed in rate base that ratepayers will pay the for the capital costs of the facility even if
2 the plant is seldom run.
3 Q. DR READING DO YOU HAVE ANY CONCLUDING REMARKS ABOUT THE
4 AVOIDED COST PROPOSALS AND THE UTILITIES' "IRP METHODOLOGY" VS
5 THE SAR METHODOLOGY?
6 A. Yes. All accepted methods (as described above) for calculating avoided costs have pluses
7 and minuses. One of the major pluses for the SAR method is its simplicity and transparent
8 nature. Idaho Power's witness Hieronymus's direct testimony references a report by Ms. Carolyn
9 Elefant. In that report she lists the "Pros" and "Cons" of the various avoided cost methodologies.
10 The "Pro" for the Proxy Method is that it is "Simple and transparent. "27
11 One of the problems with what each of the utilities is proposing is that each company
0 12 uses different models, each of which has thousands of input assumptions and algorithms that
13 neither a requesting QF nor the Commission have the resources to examine thoroughly. On the
14 other hand the SAR methodology has few enough variables that the parties and Commission
15 Staff can analyze and present their case to the Commission as to the reasonableness of the
16 utility's assumptions. The proposals offered by the IOUs put the utilities in the driver's seat for
17 the determination of avoided cost rates offered to potential PURPA projects. Added to this
18 complexity, is the number of variables the utilities propose to make between IRP' s (as discussed
27 Carolyn Elefant, Reviving PURPA Purpose: The Limits of Existing State Avoided Cost Ratemaking
Methodologies in Supporting Alternative Energy Development andA Proposed Path for Reform, p. 24.
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0 1 above) that are changed at the discretion of the utilities and not properly vetted by the
2 Commission or the parties.
3 Q. DR. READING HAVE YOU LOOKED AT THE RATE IMPACT FOR VARIOUS
4 TYPES OF PROJECTS USING THE PROPOSALS BY THE UTILITIES IN THIS
5 DOCKET?
6 A. Yes. For all types of QF projects modeled for all three utilities the proposed methods
7 have the effect of significantly lowering avoided cost rates from the current posted rates. One of
8 more curious aspects of the utilities' approach is that their proposed avoided cost rates from their
9 "IRP Method" are significantly lower than the costs of building the utilities' own resources, as
10 well as, the costs presented in their recently filed IRPs. This result should not be a surprising
11 given the above discussion about how their proposed method measures only short-run avoided
10 12 costs and contain updated lower natural gas prices and loads. What is obvious in comparing these
13 rates is that the utilities want to offer QFs significantly lower rates than what they think it costs
14 to build their own generating capacity. These comparisons clearly point out the fallacies in their
15 approach and show the difference between the "avoided costs" of their own resources and what
16 they claim is fair to offer a QF.
17 Q. COULD YOU BE MORE SPECIFIC AND DEMONSTRATE WHAT YOU MEAN
18 WHEN YOU SAY AVOIDED COSTS ARE SIGNIFICANTLY DIFFERENT BETWEEN
19 WHAT THE UTILITIES BELIEVE IT COSTS THEM TO BUILD A RESOURCE AND
20 THE AVOIDED COSTS PROPOSED TO BE OFFERED TO QFs?
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0 1 A. I will look at each utility in turn, and start with Idaho Power's calculations. The
2 Company has developed its avoided costs estimates for four hypothetical QFs each with a
3 different motive force. The four types are Baseload, Canal-drop Hydro, Fixed PV, and Wind.
4 The following four Charts depicts each of these four types with the levelized 20 year MWh costs
5 calculated by Idaho Power based on $/MWh basis. The comparison costs in $/MWh for each
6 type are based on the Company's 2011 IRP that was officially noticed by the Commission in
7 December 2011, along with the current and proposed IRP Method avoided cost calculations. For
8 Baseload comparisons Langley-Gulch values are included based on cost estimates filed by
9 Commission Staff.
10 As can be seen in the following Chart 1, the costs vary between a high of $111.13 per
11 $/MWh for Langley Gulch to a low of $47.40 per $/MWh for the Company's proposed IRP
0 12 Method. Langley Gulch is included in the baseload comparisons because it is entering the
13 Company's resource stack in June of this year. From a theoretical basis, it can be argued that
14 either the next or last generation plant is an accurate measure of the utility's marginal costs.
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Levelized
Resource Type (Capacity Factor) Cost $/Mwh Source
Lagy Gulch [300 Mw] (65%)$U14Staff Comments, lPc-Eja!HotSprin5/3/2o10
Bas&oad -Current IRP Method [20MW] $65.00 IPCo Memorandum in Support of Stay, P. 15, GNR-E-111-03
Base!oadPrçppsedHwMethod[2oMw]o%*) $440lPCo Memorandum in Support of 15NR-E-1l1-O3
Baseload
Baseload -Proposed IRP Method [20MW](92.0%**)
Baseload -Current IRP Method (20MW) 1
CCCI lxi [270 MW] 2011 IRP (65%)
Langley Gulch [300 MW) (65%)
$0 $20 $40 $60 $80 $100 $120
IRP Price Levelized $/MWh
* 90th Percentile Peak Hour Capacity Factor
2 While it might be argued each of four cost estimates are not precisely comparable, the
3 order of magnitude of the difference between the utility's baseload load plant currently coming
4 on line, and what it proposes to offer a baseload QFs, is so dramatically different it calls into
5 question the claims that the proposed method is a realistic estimate of the Company's avoided
6 cost. It is also important to note all four of these estimates can be considered falling within the
7 same time frame and are therefore comparable.
8 Q. DID YOU FIND THE SAME PATTERN OF THE AVOIDED COST PRICE
9 RELATIONSHIHP BETWEEN THE COST OF DIFFERENT TYPES OF GENERATION
10 WHEN YOU REVIEWED RMP AND AVISTA?
11 A. The costs of various types of generation found in the IRP and the avoided costs proposed
12 to be offered to a QF show, as in the case of Idaho Power, significantly lower proposed avoided
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1
1 costs. For Avista the lowest resource cost found in their IRP is $99.07 $/MWh for a CCCT.28
2 With the exception of Hydro at $114.48 per MWh the highest proposed avoided cost offered is
3 $75.30 per MWh for Solar with the lowest being $42.51 for Wind .
29 A similar comparison for
4 Rocky Mountain Power could not be made because matching the resource types between the
5 avoided costs presented in the Company's testimony and its latest IRP did not match up well.
6 However, a general comparison between the five hypothetical types are significantly lower than
7 those numerous resource types presented in RMP' s latest IRP.3° These divergent prices again
8 demonstrate that prices offered to QFs do not match what the utility believes it would cost to
9 build the type of resource and hence is not reasonable to be used as an accurate estimate of
10 avoided cost.
11 Q. COULD YOU SUMMERIZE YOUR RECOMMENDITIONS BASED ON THE
12 DISCUSSION ABOVE?
13 A. Published rates should be available for all types of QF projects less than 10 aMW based
14 on the SAR method. I do support Avista's proposal to update published rates utilizing the gas
15 SAR utilizing the ETA's Annual Outlook Report, provided that the Commission sets a
16 predetermined date applicable for the rate change. For projects over 10 aMW, what is called the
17 "IRP Method" should be used only when each utility's IRP is fully considered and approved
18 through the hearing process. Changes to variable inputs in the IRP Methodology should not be
28 Avista Corporation's 2011 Integrated Resource Plan, Chapter 6.
29 Direct Testimony of Avista Witness Clint Kalich, GNR-E-1 1-03, Table 4, p. 24.
30 Direct Testimony of Rocky Mountain Power Witness Kelcey Brown, GNIR-E- 11 -03,Table A, p. 5;
PacifiCorp's 2011 Integrated Resource Plan, Chapter 6.
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0 1 allowed between approved IRP's with the exception of natural gas prices based on EIA's annual
2 updates or from another publicly available third party source on a predetermined date. The
3 single model run approach advocated by Idaho Power should be rejected, and the models should
4 instead be run twice - once with the QF at zero cost and once without the QF. QF projects
5 should be eligible for capacity payments for the full term of their contract with no deficit period
6 allowed, and a 20 year contract term should remain the standard which is discussed further
7 below.
8
9 PART 2: OTHER QF ISSUES
10 I. LIQUIDATED DAMAGES AND DELAY SECURITY
11 Q. AVISTA COMPANY WITNESS CLINT KALICH STATES QF CONTRACTS
12 SHOULD CONTAIN A PROVISION WITH "MEANINGFUL" DELAY DEFAULT
13 LIQUIDATED DAMAGES IN HIS DIRECT TESTIMONY. DO YOU HAVE ANY
14 COMMENTS ON HIS DISCUSSION ON PAGES 31 THROUGH 33?
15 A. Yes. In addition to my comments, I have also included discovery responses by Avista
16 addressing this issue as Exhibit 503 to my testimony. "Meaningful" of course is another term
17 that is in the eyes of the beholder. Mr. Kalich recommends the Commission authorize utilities to
18 require QFs to post a security deposit equivalent to $45 per kilowatt of nameplate capacity, and
19 allow the utility to terminate the contract and keep the $45 per kilowatt deposit if the actual on
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0 1 line date is more than 180 days beyond that stated in the contract .3 ' The rationale for the 180 day
2 termination condition is the Company fears a developer may simply hold off bringing the project
3 on line if prices are falling and waiting for prices to hopefully increase. Mr. Kalich supports the
4 security provision because it creates a meaningful deterrent to delay in achieving the proposed on
5 line date. There are two major issues with what Avista (or any other utility) is proposing for
6 liquidated damages for a QF.
7 Q. WHAT IS THE FIRST ISSUE?
8 A. The first issue is that no Idaho utility has provided the Commission with any analysis on
9 a utility's likely actual damages in the event that a PURPA project either did not come on line at
10 the stated contract date or failed to come on line completely. Instead, the $45 per kilowatt delay
• 11 security amount appears to be an amount that the utilities have decided will provide adequate
12 deterrent to a breach. Avista simply conducted a survey of what other utilities have been able to
13 demand as a delay security in PPAs with independent power developers and states it has not
14 estimated the likely costs to Avista or any other utility should a QF default.32 This is out of line
15 with Commission orders, which I presume are based upon the Commission's understanding of
16 Idaho contact law.
17 With regard to a recent contract containing a delay liquidated damage security, the
18 Commission stated "the Commission is concerned that such provisions will have a potentially
19 deleterious effect upon future PURPA projects. Quite often, operators of qualified small power
Direct Testimony of Avista Witness Clint Kalich, GNR-E-11-03, pp. 32-33. 32 Avista Response to Clearwater Paper's Production Request Nos. 11, 13, and 14, contained in Exhibit 503.
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1 production facilities do not have ready access to the necessary amount of security or capital
2 delineated in this Agreement." 33 The Commission declared:

3 Therefore, the Commission finds that such provisions calling for delay security

4 should not be punitive in nature. Rather, the amount of delay security ultimately provided

5 in this case, as well as future energy sales agreements with other PURPA suppliers,

6 should constitute a fair and reasonable offset of a regulated utility's estimated increase in

7 power supply costs attributable to the PURPA supplier's failure to meet its contractually

8 scheduled operation date.
9
10 In other words, a liquidated damages provision should not operate merely as a one-way penalty
11 to deter one party from breaching the agreement. It should not be derived from a canvassing of
12 terms required by other utility purchasers because the traditional utility market is essentially a
13 monopsony market with only very limited number of purchasers in the region of any independent
14 power project. Standard terms in such a monopsony market place should not be assumed to be

15 fair. Instead, the liquidated damage provision should be an actual estimate of the likely damages
16 the non-breaching party (here, the utility) would incur. The intent should be to keep the utility
17 and its customer's whole in the event of a default. Otherwise, the provision is simply a penalty
18 provision unilaterally imposed by the party with superior bargaining strength. Avista has
19 admitted that it has made no effort to approximate its likely actual damages in the event of a QF

20 delay default. 35
21 Q. HOW WOULD YOU ESTIMATE A UTILITY'S ACTUAL DAMAGES IN THE
IPUC Order No. 30608, P. 3, Case No. IPC-E-08-09 (2008).
1d., 4.
Avista Response to Clearwater Paper's Production Request No. 13, contained in Exhibit 503.
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. 1 EVENT OF A QF'S DELAY DEFAULT?
2 A. One easy way to estimate a purchasing utility's actual damages in the event of a QF delay
3 default is to require the QF to pay the difference between the rate the utility would pay in the QF
4 contract and the actual cost for replacement power during the period the QF's delay default
5 forces the utility to secure replacement power. The replacement price would include the cost at
6 the relevant market hub plus the necessary transmission and administrative costs to secure that
7 replacement power. The period during which the utility would need to secure replacement
8 power should not last for the entire term of the power purchase agreement, which could be up to
9 twenty years, because the utility could obviously make alterative arrangements to meet its load
10 needs prior to the expiration of the 20-year contract term. The period during which the
11 breaching QF should be liable should be limited to a reasonable amount of time for the utility to
0 12 make alternative long-term arrangements to secure that amount of power. I understand that
13 Idaho QF power purchase agreements have in the past contained provisions tied to the
14 replacement price of electricity and capacity. The market price for replacement power in the
15 event of a QF default is quite low at the present time, and $45 per kilowatt is an excessive
16 amount for a QF to automatically forfeit in the event of a delay. For example, at $45 per
17 kilowatt, a 10 MW QF must provide $450,000 to the utility at the time the contract is approved.
18 Under Mr. Kalich's proposal, the utility would receive $450,000 for a 180 day delay in a QF's
19 achievement of its committed on line date. This appears far in excess of the utility's actual cost
20 for replacement power at the present time.
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0 1 It is only in the last few years that the utilities began unilaterally imposing the $45 per
2 kilowatt delay security liquidated damages provision for QF contracts. Although I am aware of
3 complaint cases where QFs have alleged that a $45 per kilowatt delay damage provision is
4 unfair, I am not aware of any QFs having fully litigating such a complaint at the Commission. 36
5 The Commission should not consider the absence of a fully litigated challenge to be
6 representative of a belief that these clauses are a fair estimation of the utility's actual damages, as
7 required by the Commission order cited above. Even for a QF with the financial resources to
8 litigate the legality of the clause, a delay caused by filing a complaint at the Commission could
9 compromise the viability of the entire project because the timing of tax credits, financing and
10 equipment supplies are critical in development of a generation project.
11 Mr. Kalich even recommends requiring the $45 per kilowatt security amount be provided
12 by the QF simply to exercise the QF's right to create a legally enforceable obligation, i.e. a
13 binding contract that would lock in the fixed avoided cost rates. Many QFs cannot secure
14 financing and access to such large amounts of money until after the PPA is signed and approved
15 by the Commission. Thus, Mr. Kalich's proposal would create a timing problem for many QFs,
16 and would obviously be a substantial hurdle for all but the most well-funded QFs.
17 For all of these reasons, if such a requirement is to be authorized by the Commission, it
18 should not be based on a flawed method of calculating the utility's actual damages, so as to
19 unnecessarily deter otherwise viable QF projects. The Commission should take the opportunity
36 See IPUC Case Nos. IPC-E-10-29 and -30; PAC-E-10-05.
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1 in this case to require the utilities to tie the delay default provision to a utility's actual damages.,
2 Q. WHAT IS THE SECOND ISSUE YOU WOULD LIKE TO MENTION WITH
3 DELAY SECURITY AND LIQUIDATED DAMAGES PROVISIONS?
4 A. Mr. Kalich notes in his testimony that the Company wants to "ensure a level playing
5 field" between the QF and the utility. 37 A true level playing field would be where the utility-
6 owned plants must be held to the same standard and issue rate payer refunds when their own
7 plants experience failures or delays. A good example is Avista's Reardan wind project that was
8 in the utility's Preferred Resource Strategy in its 2009 IRP. It was slated to come on line in 2010
9 or 2011, but now is not scheduled until 2014 or beyond. This is not to say that Avista
10 necessarily acted irrationally to replace this project with the Palouse wind RFP. I simply intend
11 to point out that utilities regularly incur expenditures for generation plants that either never come
0 12 on line or are delayed. If there are real costs to a utility and its customers that warrant a delay
13 default provision in a QF PPA, then there should likewise be compensation to the utility's
14 customers for a similar delay occurring at a utility-owned generation project. Avista's proposal
15 provides for unfair treatment to QFs and deprives the utilities' customers of a comparable market
16 check to the utilities' proposals to build their own generation resources.
17 Q. IS THERE ANYTHING ELSE THAT WOULD LEVEL THE PLAYING FIELD?
18 A. Yes, Mr. Kalich proposes only a provision that would address a default by the QF. But
19 there is the possibility that the QF could be harmed by a utility under certain circumstances, and
Direct Testimony ofAvista Witness Clint Kalich, GNR-E- 11-03, p. 33.
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0
1 therefore QF contracts should provide for compensation to the QF in the event of a utility
2 default. For example, a delay in achieving an on line date could occur solely because the utility
3 failed to complete interconnection construction as scheduled. The QF could be damaged by such
4 a delay because it could delay the project's schedule and the time by which the project would
5 start generating revenue. Such a delay by the utility in completing interconnection should not
6 result in the QF being in default on its power purchase agreement. Another potential cause of
7 damage to a QF is if the utility experiences a disruption on its system that requires curtailment of
8 the QF for a lengthy period of time. The QF should be compensated for the lost revenue and
9 other damages it might incur by the unscheduled outage. Further, as I will discuss below, Idaho
10 Power's proposed Schedule 74 curtailment provision would allow Idaho Power to curtail QFs
11 under certain circumstances. But Idaho Power's provision provides no express remedy to QFs if
12 Idaho Power implements the curtailment at an inappropriate time or in a manner that harms the
13 QF.
14 If Idaho QF PPAs will include damage provisions, they should address the possible
15 damages to the QFs also, not just the potential damages to the utilities.
16 II. AVISTA'S PROPOSAL THAT QFs MUST ACHIEVE ON LINE STATUS
17 WITHIN 2 YEARS TO OBTAIN FIXED RATES.
18 Q. DO YOU HAVE ANY COMMENTS ON AVISTA COMPANY WITNESS
19 KALICH'S RECOMMENDATION THAT QF CONTRACTS NOT BE SIGNED
20 EARLIER THAN FIVE YEARS BEFORE COMMERCIAL OPERATION AND THAT
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0 1 FIXED PRICES SHOULD BE MADE AVAILABLE NO EARLIER THAN TWO YEARS
2 BEFORE COMMERCIAL OPERATION?

3 A. Yes. A QF that is building a new project will need to secure financing before
4 commencing construction. A bank or lender is unlikely to agree to provide the money to build

5 the project until there is a guaranteed revenue stream if the project is successfully built. Mr.
6 Kalich's proposal essentially would give a new QF a maximum of two years after signing the
7 PPA within which to secure financing, and achieve on line status. For many types of generation
8 projects, it could take much longer than two years to complete construction alone. Mr. Kalich's
9 testimony contains no analysis of the impact of this 2-year requirement on a party attempting to
10 build a generation project. If adopted, the requirement would certainly deter some QF projects.
11 Q. WHAT IS MR. KALICH'S REASONING FOR THIS 2-YEAR REQUIREMENT?

0 12 A. Mr. Kalich states: "Too many things affecting price can change over a five-year term,
13 both for the QF developer and the utility."38 Apparently, Avista's concern is that the avoided
14 costs may decrease between the time of contract execution and the time the QF project is built.
15 This is another example of the utilities attempting to require QFs to provide greater assurances to
16 ratepayers than the utilities themselves would ever agree to provide.
17 Q. PLEASE EXPLAIN.

18 A. While the Company recommends this 2-year condition for a QF, the condition is
19 demonstrably inapplicable for a utility-built plant. Idaho Power received its CPCN with the
38 Direct Testimony of Avista Witness Clint Kalich, GNR-E- 11-03, p. 31.
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0 1 costs approved for Langley Gulch in September of 2009 but will not be on line until June of
2 2012. It is interesting to apply both Mr. Kalich's delay security provision proposal and his 2-
3 year on line status proposal to the Langley Gulch plant. For Langley Gulch to receive
4 guaranteed fixed rates, Mr. Kalich's proposal would require it to provide a guaranteed on line
5 date within two years of September 2009 when the Commission issued the CPCN. To obtain
6 guaranteed rate recovery for the estimated capital costs of the plant (which the Commission
7 essentially granted subject to a price cap in IPC-E-09-03), a Langley Gulch QF would have to
8 agree to an on line date no later than September 2011. Mr. Kalich would require a QF to post
9 $45 per kilowatt. For the 330 MW Langley Gulch plant approved in Order No. 30892, Idaho
10 Power would have had to post $14.8 million in September 2009 as a guarantee it would be on
11 line by September 2011. Mr. Kalich's delay default proposal would allow termination of the QF
0 12 if it were not on line within 180 days of the proposed on line date. A "Langley Gulch QF"
13 would forfeit its $14.8 million security if not on line by March 2012. Langley Gulch is still not
14 on line today in May 2012, and is not even scheduled to be on line until at least June 2012. Its
15 approval could therefore be terminated.
16 If the Commission were to apply Mr. Kalich's proposal for QFs to the Langley Gulch
17 project, ratepayers could terminate the approval of the plant today and walk away from the
18 project altogether for any reason. If Langley Gulch were no longer needed because loads had not
19 materialized as predicted by Idaho Power, or if a less expensive offer materialized in the interim,
20 the Commission and the ratepayers could walk away from project, and Idaho Power's
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1 shareholders would be responsible for any sunk costs. The prudence of Idaho Power's decision
2 in 2009 would be completely irrelevant once it went beyond the 2-year and 180 day period to
3 achieve on line status. This is not such a hypothetical situation because Idaho Power's load
4 needs are currently less than it projected when it sought approval of Langley Gulch in 2009.
5 Q. ARE THERE ANY OTHER RECENT EXAMPLES OF UTILITY PLANTS
6 TAKING LONGER THAN TWO YEARS TO ACHIEVE ON LINE STATUS?
7 A. Yes. In the case of Avista's proposed Reardan wind project, the Commission allowed
8 Construction Work in Progress (CWIP) and Accounting for Funds Used During Construction
9 (AFUDC) for the facility when the land was purchased in 2008 .
39 This treatment covered the
10 costs associated with the wind generation site land, land rights, reservation costs, and other
11 incremental costs associated with site evaluation, selection and acquisition to be accounted for as
0 12 construction work in progress. In its application requesting this preferential ratemaking
13 treatment, Avista represented that it intended for the project to be on line in 2011. To date,
14 Reardan is not on line. As pointed out above should the Reardan project ever be build, the utility
15 would request rate recovery for these costs that are on the Company's books and accruing
16 interest. The utility was able to obtain preferential accounting treatment that a QF would never
17 get, and provided no meaningful guarantees to ratepayers in exchange.
18 These two examples demonstrate that it is not at all out of the ordinary for it to take more
19 than two years from Commission-approval to bring a utility-owned generation project on line. I
IPUC Order 30611, Case No. AVU-E-08-04 (2008).
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I recommend that the Commission reject this unfair 2-year requirement. If the Commission finds
2 that a 2-year requirement is needed for QF projects to protect ratepayers, the same requirement
3 must also be imposed and enforced for utility-built projects.
4 III. IDAHO POWER'S PROPOSAL FOR 5 YEAR CONTRACT TERMS
5 Q. DO YOU HAVE ANY COMMENTS ON IDAHO POWER'S
6 RECOMMENDATION THAT THE STANDARD TERM OF A QF CONTRACT BE
7 REDUCED FROM THE CURRENT TWENTY YEARS TO FIVE YEARS?
8 A. Limiting PURPA contract terms to five years would preclude the vast majority of QF
9 developers from being able to secure financing for their projects. FERC rules, in 18 C.F.R. §
10 292.304(b)(5), (d)(2)(ii), allow a QF to lock in long term rates for the term of a contract or
11 legally enforceable obligation with estimated avoided costs calculated at the time the obligation
0 12 is incurred. In establishing this option, FERC stated:
13 Paragraphs (b)(5) and (d) are intended to reconcile the requirement that the rates for
14 purchases equal the utilities' avoided cost with the need for qualifying facilities to be able
15 to enter into contractual commitments based, by necessity, on estimates of future avoided
16 costs. Some of the comments received regarding this section stated that, if the avoided
17 cost of energy at the time it is supplied is less than the price provided in the contract or
18 obligation, the purchasing utility would be required to pay a rate for purchases that would
19 subsidize the qualifying facility at the expense of the utility's other ratepayers.
20
21
22 Many commenters have stressed the need for certainty with regard to return on
23 investment in new technologies. The Commission agrees with these latter arguments, and
24 believes that, in the long run, "overestimations" and "underestimations" of avoided costs
25 will balance out.
26
27
28
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1 Paragraph (b)(5) addresses the situation in which a qualifying facility has entered into a

2 contract with an electric utility, or where the qualifying facility has agreed to obligate

3 itself to deliver at a future date energy and capacity to the electric utility. The import of

4 this section is to ensure that a qualifying facility which has obtained the certainty of an

5 arrangement is not deprived of the benefits of its commitment as a result of changed

6 circumstances. 40
7
8 FERC intended to provide a framework within which QFs would be able to obtain financing.
9 FERC provided for rates "to deliver at a future date," and agreed with commenters who
10 suggested there was a "need for certainty with regard to return on investment in new

11 technologies." No utility-owned generation resource will be paid off within five years, and a
12 five-year term cannot provide certainty on the return on investment.
13 Q. DID IDAHO POWER PROVIDE ANY BASIS FOR ITS PROPOSED 5-YEAR
14 CONTRACT TERM LIMIT?

15 A. Company witness Mark Stokes rationalizes this proposed reduction in term as a measure

16 to protect customers. Mr. Stokes testified:

17 Finally, in order to limit the risk customers are exposed to through longer-term contracts,

18 Idaho Power urges the Commission to reduce the standard contract term from 20 years to

19 five years. Idaho Power believes all of these proposed changes will resolve several

20 problems that exist with the current implementation of PURPA in the state of Idaho, and

21 protect utility customers from further harm. 41
22
23 Mr. Stokes's reasoning sounds much like that of the rejected comments in the FERC rulemaking
24 cited above. The Company's proposal is at odds with the intent of FERC, and would discourage
25 QF development.
45 Federal Register 12,214, 12,224 (1980).
41 Direct Testimony of Idaho Power Witness Mark Stokes, GNR-E- 11-03, p. 47.
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I Q. DO YOU HAVE ANY OTHER COMMENTS ON THE PROPOSED 5-YEAR
2 CONTRACT TERM?
3 A. Yes. As discussed above in the Section dealing with the IRP methodology, when the
4 utility receives rate base treatment for one of its own generation facilities, the utility commits its

5 ratepayers to reimbursing the utility for its costs for the depreciated life of the project. The
6 capital cost recovery is guaranteed through rate base treatment and the majority of energy costs
7 are recovered annually through an annual power cost adjustment mechanism. Unlike a QF
8 project, those energy costs are not fixed and can go up dramatically from year to year. For
9 example, the price to supply Idaho Power's and PacifiCorp's jointly owned Bridger Coal Plant

10 increased significantly in 2010, and that cost increase was passed on directly to ratepayers.42

11 Utility customers are subject to fuel cost risks for utility-owned resources, but are protected from
12 the volatility of natural gas and coal prices when a fixed term QF contract is signed. I am certain
13 Idaho Power would not have been willing to build Langley Gulch if was assured of rate recovery
14 at a set rate for only a five year term rather than for the life of the project. This is yet another
15 example where the utilities propose that the Commission deprive QFs of similar treatment to the

16 utility's own generation resources.
17 IV. IDAHO POWER'S CURTAILMENT PROVISIONS
18 Q. DO YOU HAVE ANY COMMENTS ON IDAHO POWER'S PROPOSAL TO
42 IPUC Order No. 31093, at pp. 13-14, Case No. IPC-E- 10-12 (2010). The increased annual cost for
Bridger's coal was $24.8 million in 2010 to Idaho Power customers alone. Idaho Power's Application, 124, Case
No. IPC-E-10-12.
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I IMPLEMENT AN ECONOMIC CURTAILMENT TARIFF APPLICABLE TO
2 EXISTING AND NEW QFS, WHICH IS ITS PROPOSED SCHEDULE 74?
3 A. Yes. In addition to my testimony below, I have attached as Exhibit 504 to my testimony
4 several discovery responses produced to date by the Company on the topic, and Exhibit 505,
5 which is a recent decision by the Montana Public Service Commission rejecting an economic
6 curtailment proposal by North Western Energy for new QF contracts.
7 Idaho Power already possesses the right through its existing Schedule 72 to curtail QFs
8 for operational concerns to protect system reliability. In this case, the Company proposes to
9 implement economic curtailment of QFs under a proposed Schedule 74. Company witness
10 Tessia Park explains why she believes a FERC rule, 18 C.F.R. § 292.304(f), allows for the
11 Commission to approve the Company's proposal, even for existing QFs with long-term contracts
9 12 with fixed avoided cost rates and existing curtailment provisions. Ms. Park explains that she
13 believes the federal regulation and associated orders allow that "utilities may curtail higher cost
14 QF energy if the utility would have to dispatch less efficient, higher cost units (other than base
15 load units) to meet system load."43
16 In general, Ms. Park advocates for the right to curtail QFs during certain light loading
17 periods so as to avoid uneconomic operation at several Company-owned facilities that the
18 Company characterizes as "base load." The proposed Schedule 74 tariff attached to Ms. Park's
19 testimony includes the following as "base load" resources: Company-owned hydroelectric
Direct Testimony of Idaho Power Witness Tessia Park, GNR-E- 11-03, p. 18.
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.

1 resources, including all run-of-river generators and the Hells Canyon Complex, coal-fired
2 generating resources (Jim Bridger generating plant, Valmy generating plant, and the Boardman
3 generating plant), and the Langley Gulch power plant. 44
4 Q. DO YOU HAVE ANY COMMENTS ON THE COMPANY'S PROPOSAL?
5 A. Yes. First, I am not an attorney, so I will not provide a legal opinion. However, it strikes
6 me as out of the ordinary to reach back in time to revise existing contracts. QFs have built and
7 secured financing of their projects based on assurance that the contractual provisions would be
8 honored by Idaho Power.

9 Also, Idaho Power appears to take issue primarily with intermittent QFs in its testimony.
10 But the issue identified by Idaho Power is already addressed in the existing contracts through a
11 wind integration charge. The Commission approved a wind integration charge for Idaho Power,
0 12 which reduces the otherwise available avoided cost rates for wind QFs and was developed
13 through a lengthy process, and ultimately a settlement of a contested case, to compensate the
14 Company and its customers for the estimated costs of wind integration. The wind integration
15 charge was a component of the estimate of future avoided costs at the time of contracting.

16 Ms. Park's attempts to explain why the Company's proposed curtailment provision
17 addresses different circumstances from the wind integration charge is not very convincing. In
18 response to the question of whether the $6.50 per MWh wind integration charge covers the cost

19 of balancing services, she testifies: "Partially. As an initial matter, it is important to point out
Jd., Exhibit No. 5,p. 1.
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0 1 that the $6.50 wind integration charge was the result of a negotiated settlement and is not
2 reflective of the Company's actual integration costs."45 Idaho Power appears to take the position
3 that it can change the terms of its prior settlement agreement which has now been incorporated
4 into the avoided cost rates in many QF contracts. Idaho Power appears to believe that the
5 "actual" wind integration charges are different from those set forth in the existing PPAs, and
6 therefore an additional economic curtailment provision is necessary to make up the difference.
7 If the wind integration charge of $6.50 per MWh in existing contracts were found by the
8 Commission to be in excess of Idaho Power's actual wind integration costs, I doubt that Idaho
9 Power would agree (or the Commission would require it) to adjust the avoided cost rates in those
10 contracts upwards. The same is true of any other component of the avoided cost rates. The
11 avoided costs and all components thereto are estimates of actual avoided costs, which could be
0 12 higher or lower than actual projected costs. It does not appear fair to me for Idaho Power to try
13 to essentially impose additional wind integration charges through an economic curtailment
14 provision, any more than it would be fair for Idaho Power revise the avoided cost rates in any
15 other manner in any existing QF contract.
16 Q. DOES THE COMPANY'S PROPOSAL APPEAR TO DESCRIBE A SITUATION
17 SIMILAR TO THAT DESCRIBED IN THE FERC ORDERS THE COMPANY CITES?
18 A. I do not believe so. In developing 18 C.F.R. § 292.304(f), FERC stated:
Id., p. 13.
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1 This section was intended to deal with a certain condition which can occur during light

2 loading periods. If a utility operating only base load units during these periods were

3 forced to cut back output from the units in order to accommodate purchases from

4 qualifying facilities, these base load units might not be able to increase their output level

5 rapidly when the system demand later increased. As a result, the utility would be required

6 to utilize less efficient, higher cost units with faster start-up to meet the demand that

7 would have been supplied by the less expensive base load unit had it been permitted to

8 operate at a constant output.46
9
10 This language discusses a circumstance where a utility that operates only slow-ramping base

11 load facilities, such as a coal plants, would have to be back down those units during light loading
12 periods to accept QF output, but could not then start those units back up quickly enough to meet
13 the utility's next peak. The FERC regulation would apply if the utility had to instead meet the
14 next peak with a more expensive peaking resource, such as a less efficient gas peaking unit.
15 This does not appear to apply to Idaho Power for several reasons.

16 Idaho Power does not meet its load solely with slow-ramping base load coal plants. It
17 also meets its load with its hydroelectric plants and will soon meet load with its Langley Gulch

18 Plant, which it specifically described at the time of its request for its CPCN as being useful for

19 wind integration.
20 Q. HAS IDAHO POWER ADEQUATELY DEMONSTRATED THAT ITS SYSTEM
21 CONFIGURATION IS SIMILAR TO THE SCENARIO CONTEMPLATED BY THE
22 FERC RULE?
46 45 Federal Register 12,214, 12,227 (1980).
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1 A. No. The Company's discovery responses have not demonstrated that the circumstance
2 described by FERC would ever exist for Idaho Power. The Company's whole proposal hinges
3 on Idaho Power's position that it has a certain level of "must-run" generation, which cannot be
4 scaled back to accept the QF output it is contractually obligated to accept and buy when it is
5 provided. According to the Company, it must therefore curtail QFs.

6 Specifically, the Company lists the following resources as having the following "must-
7 run" output during typical low loading times of the year: Hells Canyon Complex (no less than
8 350 MW), Mid-Snake "run-of-river" hydroelectric projects (450 MW), the Bridger and
9 Boardman thermal units "that are 'in the money" (300 MW), and non-intermittent PURPA
10 generation (50 MW).47 That totals 1150 MW. Ms. Park testifies: "If Idaho Power were to cycle
11 off its thermal units in the middle of the night to accommodate PURPA generation, the Company
0 12 would need to start up its higher cost, less efficient natural gas peaking units or make more
13 expensive market purchases (assuming transmission would be available) to meet system load
14 during heavy load hours during the next day."48 There are several gaps in Idaho Power's logic.
15 Q. WHAT ARE THE GAPS IN IDAHO POWER'S LOGIC?

16 A. First of all, FERC's description does not state that curtailments would occur when the QF
17 purchases may cause the utility to enter into more expensive market purchases; it refers to

18 operational circumstances at specific utility plants.
Direct Testimony of Idaho Power Witness Tessia Park, GNR-E-1 1-03, pp. 23-24.

48 Id, pp. 24-25.
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0 1 Second, Ms. Park appears to state that its coal plants can be taken off-line and brought
2 back on line provided that Idaho Power gives the plant's operating utility up to one week
3 notice. 49 Thus, if Idaho Power can go a week without needing its coal plants during these light
4 loading periods, it appears to have no need to have them on line to begin with for operational
5 purposes. Idaho Power seems to suggest that it typically has such large load swings day-to-day
6 during these light loading times of the year that it must keep its Bridger and Boardman coal
7 plants on line to meet its peak loads during these times of the year. The actual load swings
8 within the weeks following light loading events of less than 1100 MW in the years 2010 to 2011
9 are contained in Idaho Power's Response to Exergy Production Request No. 22, contained in my
10 Exhibit 504. Although I am not an operations expert, it does not appear to me that Idaho Power
11 has fully considered whether it would really need to run gas peakers if it were to take more units
0 12 at the coal plants off-line during weeks where it expected a light loading event. Without the full
13 300 MW of minimum generation coal on line, as Idaho Power assumes there must be, there is a
14 reduced need to curtail QFs during a minimum loading event.
15 Another problem with Idaho Power's analysis is that it assumes it must run and accept
16 output from its run-of-river hydroelectric projects, and must curtail existing QFs to do so during
17 light loading periods. Idaho Power takes the position that this 450 MW of generation cannot be
18 taken offline to accommodate QF deliveries. However, Idaho Power stated in discovery that it
19 has the operational capability to run water through those projects (or spill it) without generating
Direct Testimony of Idaho Power Witness Tessia Park, GNIR-E-1 1-03, p. 22.
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0 1 electricity.50 Idaho Power has not asserted that the FERC licenses prohibit it from taking the
2 plants offline in order to accommodate system reliability concerns such as a light loading event
3 where it has excess generation. Nor has Idaho Power asserted that the plants cannot be brought
4 back on line quickly if QF generation were to drop off or loads were to pick up.
5 Q. ARE THERE ANY OTHER FLAWS IN THE LOGIC OF IDAHO POWER'S
6 PERCEIVED RIGHT TO ECONOMIC CURTAILMENT?
7 A. Yes. Idaho Power appears to assume that it must keep the Bridger and Boardman Coal
8 plants on line during these periods where it experiences light loading. Its statement that it cannot
9 take coal plants offline is inconsistent with its statement that it does in fact take Valmy offline
10 during these periods "because of its relatively high dispatch cost and because it is not needed to
11 serve load during these low load times of year."51 Idaho Power appears able to take its coal
0 12 plants offline when it chooses to do so for its own reasons. Idaho Power appears to be
13 predetermining that certain coal plants will be "in the money" and therefore are "must run"
14 during a light loading event, even if running the coal plants to facilitate off-system sales means
15 Idaho Power must curtail QFs for general economic purposes. Idaho Power will soon have
16 Langley Gulch on line, and part of Idaho Power's justification to the Commission for that plant
17 was that it would be useful for integrating wind. It is not clear why Langley Gulch, the Hells
18 Canyon, and Mid-Snake hydroelectric projects, supplemented by occasional market purchases,
19 cannot be used to integrate wind during these light loading periods.
50 Idaho Power Response to Exergy Production Request No. 19, contained in Exhibit 504.
Direct Testimony of Idaho Power Witness Tessia Park, GNR-E- 11-03, p. 23, note 1.
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0 1 Q. WOULD IDAHO POWER'S PROPOSAL APPLY TO ALL QFS?

2 A. No. Idaho Power has only requested that the proposal apply to any QFs over 10 MW
3 with a generator limiting device Idaho Power can use remotely (regardless of resource type).
4 Although Idaho Power designated the list of such QFs to be confidential, one can conclude from
5 the testimony that it would only affect more recently built QFs, for the time being. However, it
6 is also apparent that Idaho Power's economic curtailment provision would not apply to the four
7 QF projects owned by Idaho Power.

8 Q. DID YOU SAY IDAHO POWER OWNS QF PROJECTS THAT SELL TO
9 IDAHO POWER?

10 A. Yes. Idaho Power is a 50% owner, through a subsidiary named Ida-West Energy, of
11 four hydroelectric projects that sell QF output to Idaho Power. Those projects are South Forks
12 (8.2 MW), Hazelton B (7.7 MW), Wilson Lake (8.4 MW), and Falls River (9.1 MW). Idaho
13 Power's QFs are all under 10 MW, and therefore Idaho Power's QF projects would not be
14 subject to Idaho Power's economic curtailment tariff that applies to other QFs.
15 Q. DO YOU HAVE ANY OTHER COMMENTS ON THE CURTAILMENT
16 PROPOSAL?

17 A. Yes. Idaho Power provided the Commission with state utility commission orders from
18 Nevada and Florida implementing FERC's curtailment rule. I am aware of a more recent state
19 commission order addressing this curtailment issue. Just last year, the Montana Public Service
20 Commission rejected a request by North Western Energy to prospectively include an economic
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0 1 curtailment provision in future QF contracts. That decision is attached as Exhibit 505. The
2 Montana Commission found that the FERC regulation allowed for curtailment only in very
3 limited circumstances. The Montana Commission stated: "If market conditions occasionally
4 result in prices less than NWE's tariffed avoided costs, that is not in itself a sign that the
5 principle of consumer indifference is unlawfully being violated—no more than if a long-term
6 acquisition of NWE's own were to result in a fixed-and-variable cost-per-unit which were higher
7 than prices available on the spot market. ,52

8 That order also cited to the Montana regulation on the subject, which states: "Failure to
9 properly notify the qualifying facilities and the commission or incorrect identification of such a
10 period will result in reimbursement to the qualifying facility by the utility in an amount equal to

11 that amount due had the qualifying facility's production been purchased ."53 This is consistent
12 with FERC's description of its own provision, which stated: "any electric utility which fails

13 to provide adequate notice or which incorrectly identifies such a period will be required to
14 reimburse the qualifying facility, for energy or capacity supplied as if such a light loading period
15 had not occurred. ,54 In contrast, Idaho Power does not propose any provision whereby it would
16 be required to compensate QFs for inadequate notice, or for an improperly implemented

17 curtailment.
52 Montana PSC Order No. 7172, 112, contained in Exhibit 505.
Id., 16 (citing Montana Administrative Rule § 38.5.1903(1)).
45 Federal Register 12,214, 12,228 (1980).
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1 The Commission may find this more-recent Montana order addressing a proposal for new
2 QF contracts useful in evaluating Idaho Power's proposal for existing QF contracts.
3 Q. DO YOU HAVE ANY CONCLUDING REMARKS ON THE CURTAILMENT
4 ISSUES?
5 A. Idaho Power acknowledges that it already possesses a tariff that allows for curtailment
6 for system integrity purposes, Schedule 72. Existing QFs agreed to circumstances under which
7 Idaho Power could curtail them for operational purposes when they decided to proceed with
8 building and operating their QF projects. I will let the lawyers debate the legality of unilaterally
9 amending contracts. However, I believe Idaho Power's proposal to alter the settled relationships
10 in PPAs would not be a policy that would encourage QF development. I am not convinced Idaho
11 Power meets FERC's criteria for limited operational curtailment, even for new QF projects. I
1012 recommend that the Commission not approve Idaho Power's proposed economic curtailment for
13 any QFs.
14 V. OWNERSHIP OF ENVIRONMENTAL ATTRIBUTES
15 Q. DO YOU HAVE ANY COMMENTS ON OWNERSHIP OF ENVIRONMENTAL
16 ATTRIBUTES?
17 A. I have very limited comments on ownership of environmental attributes, and have
18 included Exhibit 506 which contains a discovery response on the topic. Idaho utilities have
19 attempted at least twice to obtain a Commission order declaring the utility the owner of
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1 environmental attributes in Idaho QF contracts. 55 The Commission has never allowed the
2 utilities to insist on such a provision, and Idaho Power affirmatively disclaimed ownership in its
3 QF PPAs until recently. Some Idaho utilities have recently begun insisting on a contract
4 provision that clouds a QF's title to the environmental attributes by declaring ownership to be
5 governed by controlling law as it may exist at some future time during the term of the agreement.
6 This unilateral insistence on a term that QFs disagree with is a good example, like the delay
7 security issue addressed above, of an issue the Commission should resolve to provide
8 predictability in the QF market place. Idaho Power has described in a discovery response in this
9 case how it has been able to obtain certain QFs' agreement in last year to give Idaho Power some
10 of the QFs environmental attributes for no additional compensation, after Idaho Power first
11 insisted on a contract clause that clouded the QF's title to the environmental attributes. 56
0 12 Only Rocky Mountain Power witness Paul Clements has proposed to address ownership
13 of environmental attributes in this case. 57 He believes that the utilities should own the
14 environmental attributes without providing any additional compensation to the QF over and
15 above the avoided costs of energy and capacity. Neither Idaho Power nor Avista requested any
16 specific order on the issue in this docket.
17 Q. WHAT IS YOUR OPINION DR. READING?
18 A. In my opinion, insisting on utility ownership of RECs or insisting on a PPA clause
IPUC Case No. IPC-E-04-2; IPUC Case No. AVU-E-09-04.
56 Idaho Power Response to Exergy Production Request No. 2, contained in Exhibit 506.
Direct Testimony of Rocky Mountain Power Witness Paul Clements, GNR-E- 11-03, pp. 7-10.
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1 clouding a QF's title and is not fair. The avoided costs in Idaho compensate QFs only for the
2 energy and the capacity provided. It appears the utilities' are making every effort in this case to
3 keep the compensation to QFs as low as possible. To also assert that the utility owns the non-
4 energy attributes of QF generation without any additional compensation is unreasonable. The
5 legal issues regarding ownership of environmental attributes are currently being litigated in
6 another docket, and I understand that it has been fully submitted with legal briefing for a few
7 months now.58 I recommend that the Commission resolve this dispute as soon as possible by
8 requiring the utilities to disclaim ownership of the environmental attributes for which they refuse
9 to compensate QFs.
10 VI. QF CONTRACTING PROCESS TARIFF
11 Q. DO YOU HAVE ANY COMMENTS ON ROCKY MOUNTAIN POWER'S AND
•12 IDAHO POWER'S PROPOSALS THAT THE COMMISSION ADOPT A TARIFF THAT
13 WOULD ESTABLISH A CONTRACTING PROCESS?
14 A. Yes. Both utilities have expressed support for a contracting tariff so far in this case, but
15 only Rocky Mountain Power has actually proposed a specific tariff. Rocky Mountain Power
16 witness Paul Clements provided a proposed Schedule 38 for non-standard QF contracts, which
17 he states is based on tariffs used in Wyoming and Utah.59 Idaho Power witness Mark Stokes
18 expressed the Company's support for a contracting tariff, but he provided no specific tariff upon
58 IPUC Case No. 1PCE1115.
202.
Direct Testimony of Rocky Mountain Power Witness Paul Clements, GNR-E- 11-03, pp. 2-7 and Exhibit
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9 1 which any party can comment. The Company stated in discovery that it thought providing a
2 tariff with its initial filing would be premature. That is of course entirely inconsistent with its
3 submittal of a curtailment tariff proposed as its Schedule 74.
4 Q. DO YOU BELIEVE THAT A QF CONTRACTING TARIFF WOULD BE
5 USEFUL?
6 A. Yes, but only if the process is designed to prevent a utility from imposing unnecessary
7 delays in negotiations and only if the tariff requires meaningful deadlines with which the utility
8 must comply. Rocky Mountain Power's tariff fails on both of these requirements.
9 Q. WHAT ARE THE PROBLEMS WITH ROCKY MOUNTAIN POWER'S
10 PROPOSED TARIFF?
11 A. First of all, it only addresses a contracting process for non-standard QFs seeking
0 12 individually calculated avoided cost rates, and therefore provides no assurance that any particular
13 process will be followed for small QFs seeking published rates and standard contract terms.
14 Second, as Mr. Clements acknowledges, the deadlines for the utility to respond to QF
15 requests are far longer than deadlines authorized by the other states' tariff from which Mr.
16 Clements supposedly developed the proposed Idaho tariff. Specifically, Mr. Clements proposes
17 a 45-day response period for the utility to provide a draft contract after indicative pricing is
18 provided and all required information is submitted by the QF. This is an unnecessary and
19 excessive delay in the negotiating process. It is very difficult to believe that a sophisticated
20 utility like PacifiCorp cannot easily complete what should be a standard draft contract within a
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1 shorter timeframe than 45 days.
2 Q. DO YOU HAVE AN ALTERNATIVE PROPOSAL?
3 A. I propose using the standard contracting tariffs approved by the Public Utility
4 Commission of Oregon. These tariffs were developed in a fully litigated proceeding (Oregon
5 Commission Docket No. UM 1129), not by a utility's own efforts to improve the tariffs of
6 another commission. Both Rocky Mountain Power (operating as PacifiCorp doing business as
7 Pacific Power and Light in Oregon) and Idaho Power already have experience using these
8 standard contracting procedures. PacifiCorp's Oregon Schedule 37 for standard QF contracts
9 and Schedule 38 for large QF contracts are both available on line. 60 Idaho Power's Oregon
10 Schedule 85, which addresses both standard and non-standard contracting practices, is also

11 available on line.6'

0 12 The Oregon tariffs for small QFs include a reasonable list of required information the QF
13 must provide to obtain a draft PPA, and require the utility to respond to QF inquiries within 15
14 business days. For large QFs, the utility must respond to inquiries within 30 days, and must
15 provide a final contract within 15 business days of agreement to all terms. This is a more
16 reasonable turn-around time than the 45 days proposed by Rocky Mountain Power. Each tariff
17 also includes a standard tariff contract for small QFs to limit the need to engage in protracted
18 negotiations for small QFs. The Oregon standard contracts in the Oregon tariffs may contain
19 some terms inconsistent with existing Idaho Commission precedent on certain terms, such as the
60 http://www.pacificorp.com/es/cg/cQfb.htm1.
61 httD://www.idahopower.com/AboutUs/RatesRegu1atory/Tariffs/tariffPDF.cfin?id=269.
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1 90/110 band. Thus, I believe a standard Idaho contract should be developed and made publicly
2 available based upon existing Idaho orders, which already address many of the material terms of
3 aQFPPA.
4 I recommend the Commission adopt these standard tariff requirements based on the
5 Oregon tariffs, or some form of reasonable substitute with similar requirements.
6 Q. DO YOU HAVE ANY SUGGESTED IMPROVEMENTS IN THE EVENT THAT
7 THE COMMISSION DOES NOT UNDERTAKE TO MAKE AVAILABLE A
8 STANDARD CONTRACT DELINEATING ALL TERMS AND CONDITIONS?
9 A. Yes, even without a publicly available standard contract setting forth all terms, many
10 terms in QF PPAs have been set by the Commission through its history of implementing
11 PURPA. In the past, when the utilities have sought to implement a new condition in QF
0 12 contracts, the utilities have filed an application seeking Commission approval prior to
13 implementing such new conditions. For example, Case No. IPC-E-04-2, where Idaho Power
14 sought, but did not receive, approval to start including a term in QF contracts that declared Idaho
15 Power would have a right of first refusal to purchase any renewable energy credits generated by
16 a QF selling at avoided cost rates. Also, in Case No. IPC-E-03-16, Idaho Power filed an
17 application to modify insurance and lien rights authorized as satisfactory risk mitigation
18 measures in levelized QF contracts. In Case No. IPC-E-07-04, Idaho Power applied for
19 Commission approval of its proposal to implement daily load shape pricing in QF contracts. In
20 each of these cases, interested parties had the opportunity to comment on the utility's proposal,
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0 1 and the Commission approved a term that was less onerous on QFs than that initially sought by
2 the utility.
3 More recently, the utilities have simply begun inserting major new terms into QF
4 contracts when QFs have requested PPAs, without first obtaining Commission approval in
5 proceeding where all parties can comment. Recent contract terms implemented in this manner
6 include the delay security liquidated damages provisions and the terms clouding the QF's title to
7 environmental attributes, discussed above. The utilities then rely upon the Commission orders
8 approving contracts that contain such clauses as though the clauses were fully vetted with
9 comments by all interested parties in an open process. Vetting new contract terms in an
10 individual contract approval case is inappropriate because few QFs are likely to comment in
11 opposition to approval of the contract, knowing that the developer at issue must be anxious to
12 secure Commission approval. I recommend that the Commission admonish this new utility
13 practice of unilaterally inserting clauses into QF contracts without first seeking Commission
14 approval that the term is fair.
15 Q. DO YOU HAVE ANY OTHER SUGGESTIONS FOR QF TARIFFS?
16 A. Yes. FERC's regulations allow QF to choose to sell to a utility on an "as available" or
17 nonfirm basis, rather than pursuant to a legally enforceable obligation over a specified term.62
18 The rates are calculated at the time of delivery, rather than at the time that the QF obligates itself
19 to a legally enforceable obligation. In today's market, the "as available" rates will be lower than
62 18 C.F.R. § 292.304(d)(1).
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9 1 those in a contract over a specified term because market prices are lower than the cost to procure
2 a new resource. However, an "as available" contract option is useful to many QFs, and would
3 provide the utility with low-cost power in certain circumstances.
4 For example, if a QF is unable to resolve a dispute with a utility prior to its project
5 coming on line, an "as available" contract can provide the QF with the opportunity to complete
6 construction and achieve commercial operation prior to resolving the dispute. This may also be a
7 useful option for QFs who would prefer to use their generation to serve their own load during
8 most of the time, but sell to the utility "as available" when the output is not needed or desired to
9 meet the QF's host load.
10 Q. WHAT IS YOUR RECOMMENDATION?
11 A. Idaho Power has a tariff contract for nonfirm or "as available" deliveries in its Schedule
0 12 86, but neither Avista nor Rocky Mountain Power have such a tariff standard contract for
13 nonfirm deliveries. A tariff contract is important for QFs seeking to exercise this element of
14 FERC's regulations because a QF may want to exercise this option to make nonfirm deliveries
15 on short notice, such as in my example where the QF is unable to reach agreement with the
16 utility on the terms of a long term contract. I recommend that Avista and Rocky Mountain
17 Power also file a nonfirm standard contract similar to Idaho Power's Schedule 86. QFs should
18 have the opportunity to comment on the proposed standard contracts prior to Commission
19 approval.
20 VII. TRANSMISSION AND INTERCONNECTION ISSUES
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0 1 Q. DO YOU HAVE ANY RECOMMENDATIONS WITH REGARD TO QF
2 TRANSMISSION AND INTERCONNECTION ISSUES?
3 A. I believe this is another issue where QFs are providing benefits to ratepayers in excess of
4 what a utility's own resources will provide. Under the existing Idaho precedents, PURPA QF

5 projects are solely responsible for the interconnection costs required to interconnect their
6 proposed projects to the utilities' systems, and are almost always responsible for the network
7 transmission upgrades required to deliver their energy from the point of interconnection with
8 utility's system to load. In some cases, Idaho Power and the ratepayers have shared in the cost of
9 network upgrades. 63 Essentially, under those few authorized sharing arrangements, the QF pays
10 25% of the total cost regardless of its performance, and it obtains a refund of an additional 50%

11 paid up front only if it performs.

0 12 In contrast, all prudently incurred interconnection and transmission costs associated with

13 a utility-owned project will be included in customer rates. Similarly, when federal jurisdiction
14 applies to an interconnection, developers receive a refund for the entire cost of network
15 transmission upgrades required for their projects under FERC interconnection rules.64

16 The Commission could improve its existing precedent on this issue in two ways. First,
17 the existing cost sharing arrangement is non-binding based upon the Commission orders
18 implementing it. The Commission should provide QFs with the assurance of an established
63 IPUC Order No. 32136, Case No. IPC-E-09-25 (2010). 64 Standardization of Small Generator Interconnection Agreements and Procedures, FERC Order No. 2006, at
140, Docket No. RMO2-12 (May 12, 2005).
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0 1 policy. Second, the policy should treat QFs the same as the alternative to QFs. QFs should be
2 treated the same as the utilities and other developers. When the Montana Public Service
3 Commission recently examined this issue it stated North Western Energy "improperly sought to
4 assign all network upgrade costs to the QF instead of the amount of those costs that exceeded
5 what [North Western Energy] otherwise would incur to connect its avoidable resource. ,65 This is
6 a fair approach, and I recommend that the Idaho Commission establish the same policy for equal
7 treatment by entitling the QF to 100 percent refund of network transmission upgrades on similar
8 terms to those provided for FERC jurisdictional interconnections.
9
10 CONCLUSION
11 Q. DR. READING, DO YOU HAVE AN CONCLUDING COMMENTS REGARDING
1012 THIS DOCKET AND YOUR RECOMMENDATIONS?
13 A. Yes, I do. I am fully cognizant of the situation Idaho Power is in with respect to the
14 magnitude of wind generation it is being required to integrate into its system. I believe, based on
15 my many years of involvement in utility regulation in Idaho, that this was part of the genesis of
16 this docket. I also believe Idaho Power, along with the other two investor-owned utilities, is
17 using that fact to dismantle PURPA in Idaho without regard for the ratepayer or this
18 Commission's obligations under PURPA. The SAR methodology has been resilient in the past
65 In re North Western Energy's Application for Approval ofAvoided Cost Tarfffor New Qualifying Facilities,
Montana PSC Docket No. D2010.7.77, Order No. 7108e, p. 32, 184 (Oct. 19, 2011), available online at
htto://psc.mt.govfDocs/ElectronjcDocuments/
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1 in responding to changed circumstances, and it continues to stand out as the single best
2 methodology for this Commission to use in fulfilling its obligations under PURPA.

3 I do not accept Idaho Power's "the sky is falling" basis for making wholesale destructive
4 changes to the PURPA implementation that has taken this Commission years to develop and fine
5 tune. The Commission currently has the tools at hand to respond to changing economic
6 conditions while at the same time properly implementing PURPA.
7 Q. YOU HAVE BEEN QUESTIONED IN THE PAST AS TO THE, IF YOU WILL,
8 INTEGRITY OF YOUR TESTIFYING ON BEHALF OF THE PURPA INDUSTRY
9 WHILE ALSO TESTIFYING ON BEHALF OF RATEPAYERS - SPECIFICALLY THE
10 INDUSTRIAL CUSTOMERS OF IDAHO POWER. CAN YOU ADDRESS THAT
11 PERCEIVED CONFLICT?

0 12 A. I would be happy to do so. To find evidence that the ratepayers and the PURPA

13 industry's interests are aligned, one need look no farther than the first page of my testimony. I
14 am testifying today on behalf of Avista' s largest retail customer who also is Avista's largest
15 PURPA vendor. I am also testifying on behalf of one of Idaho Power's largest customers who is
16 also one of Idaho Power's largest PURPA vendors. Finally, I am testifying on behalf of Idaho's
17 largest and most successful PURPA wind developers. The fact that these three entities have
18 common ground in promoting a reasonable and fair implementation of PURPA in opposition to

19 the three investor-owned utilities is significant because all three live in the real world.
20 Q. PLEASE EXPLAIN WHAT YOU MEAN BY THE "REAL WORLD"?
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1 A. First, none of my clients operate in a state sanctioned monopoly environment and none
2 are virtually assured a return on investment. All are rational actors in highly competitive
3 industries. The fact that all three see a need to have a robust independent power market and at
4 the same time have fair retail rates is not an oxymoron - it is in the best interests of both the
5 PURPA developers and the ratepayer. The single fact that sophisticated self-interested
6 ratepayers have joined forces with a sophisticated self-interested PURPA developer to advocate
7 against the PURPA-killing proposals made by the utilities is compelling -- and should be very
8 instructive to the Commission as it deliberates on the many complex and difficult issues
9 presented in this docket.
10 Q. DOES THAT CONCLUDE YOUR TESTIMONY ON MAY 4,2012?
11 A. Yes it does.
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0 1 INTRODUCTION
2
3 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

4 A. My name is Don Reading and my business address is 6070 Hill Road, Boise, Idaho.
5 Q. ARE YOU THE SAME DON READING THAT FILED DIRECT TESTIMONY IN
6 THIS CASE ON MAY 4,2012?

7 A. Yes lam.
8 Q. WHAT IS THE PURPOSE OF YOUR REBUTTAL TESTIMONY?

9 A. I will be rebutting certain aspects of the direct testimony of Commission Staff witnesses
10 Mr. Rick Sterling and Dr. Cathleen McHugh. Specifically, I will discuss Mr. Sterling's positions
11 on REC ownership, the use of a SCCT for determining capacity costs, Idaho Power's Schedule

12 74, fuel cost risk, and contract length; and Dr. McHugh's position on the first deficit year
13 approach in the calculation of avoided cost rates offered to PURPA projects. There are numerous
14 other positions they take in their testimony that I have already countered in my direct testimony.
15 Therefore, although I continue to oppose those positions, I will not again challenge them here.
16 Q. WHAT COMMENTS DO YOU HAVE ABOUT MR. STERLING'S
17 RECOMMENDATIONS ON THE OWNERSHIP OF RENEWABLE ENERGY CREDITS
18 ("RECS") CREATED BY QF GENERATION?

19 A. Mr. Sterling states that he believes the issue of REC ownership should be resolved in this
20 case, agreeing with Rocky Mountain Power and opposing Avista's recommendation that the
21 ownership of RECs should be decided in a separate case (Idaho Power was silent on the issue).
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0 1 Mr. Sterling presents a review of the arguments over who should own the RECs' and
2 acknowledges,

3 "All of the arguments.. . . have merit and may be persuasive in justifying REC
4 ownership be (sic) either the utility or the QF."2
5
6 However, he decides that REC ownership should be granted to the purchasing utilities.3 He

7 supports this decision with several assertions.
8 Q. COULD YOU PLEASE OUTLINE MR. STERLING'S ARGUMENTS AND
9 COMMENT ON THE LOGIC OF THOSE ARGUMENTS?

10 A. Yes. In concluding that purchasing utilities should be granted REC ownership, he argues:

11 "[i]f Idaho was in a position where additional incentive was needed in order to

12 stimulate further development of renewables or achieve an RPS standard, then it

13 might be reasonable to assign ownership of RECs to QF project owners so that

14 they would have an additional revenue stream that could enhance project

S 15 economics. However, as recent history demonstrates, Idaho is not in a situation

16 where renewables development is stalled or needs to be accelerated. "4
17
18 Mr. Sterling's argument is thus, most simply, that recent history demonstrates renewable
19 development is neither stalled nor in need of acceleration, and therefore PURPA projects do not
20 need the benefit of REC ownership. However, this is a rearview mirror look at the QF industry in

21 Idaho, and it belies the thrust of his testimony and the proposals of the utilities going forward.

22 The positions taken by Mr. Sterling and the utilities in this case will certainly produce
23 unfavorable rates for REC-producing wind and solar projects. Mr. Sterling recommends
Direct Testimony of Rick Sterling, Idaho Commission Staff, pp. 39-42, GNR-E-1 1-03.
2 lbid.,p. 42.
Ibid.
4
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1 abandoning the SAR method for the calculation of avoided cost rates for wind and solar projects
2 larger than 100 kW, ". . . admittedly mostly due to its ability to produce favorable rates" under
3 PURPA contracts.5 There is no rational basis for Mr. Sterling's recommendation to award RECs
4 to the purchasing utility rather than the QF. As I stated in my direct testimony, if the
5 Commission were to accept the proposal advocated by the utilities and supported by Mr.
6 Sterling, the result would be "PURPA-killing."6
7 Q. DOES MR STERLING PRESENT OTHER ARGUMENTS IN SUPPORT OF HIS
RECOMMENDATIONS REGARDING REC OWNERSHIP?
9 A. Yes. He concludes that utility ownership of RECs is consistent with the IRP method of
10 calculating avoided cost rates. He states,
11 Q. Aside from the need for the Commission, the Legislature, or the courts to
10 12 determine REC ownership, are there pricing issues associated with RECs that
13 need to be considered in setting avoided cost rates?
14 A. Yes, there are. For example, under the IRP methodology, a utility's 20-year
15 portfolio of new resources is modeled in computing avoided cost rates. Each
16 utility's 20-year resource portfolio contains some renewable plants because they
17 either represent the lowest cost resources or because they help satisfy expected
18 RPS requirements or both. The utility would possess the RECs associated with
19 resources contained in its preferred portfolio, and presumably any price premium
20 associated with those RECs would be included in the cost of the projects.
21 Consequently, the cost of RECs would, already be accounted for in computing
22 avoided cost rates using the IRP methodology. Therefore, a utility paying the
23 computed avoided cost to a QF under the IRP methodology should be entitled to
24 ownership of the RECs.7
25
26 There are two significant problems with Mr. Sterling's testimony.
5 Ibid.,p.6.
6 DfrCCt Testimony of Don Reading, Joint Parties, p. 69, GNR-E- 11-03.
7 Direct Testimony of Rick Sterling, Idaho Commission Staff, p. 46, GNR-E- 11-03 (underscoring added).
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I Q. WHAT ARE THOSE PROBLEMS?
2 A. I underscored the first problem in the quote above where Mr. Sterling mentions the need
3 for the Commission, the Legislature, or the courts to "determine REC ownership." This "need"
4 cannot be dismissed as a mere aside. It is a fundamental determination that must be addressed
5 before the Commission can proceed into the REC morass. Ms. Grow, Idaho Power's Vice
6 President of Power Supply, prefiled testimony on this issue stating:

7 "the Idaho Legislature, which is currently in session, may be considering

8 proposed legislation that would address the ownership of RECs from PURPA QF

9 projects, and thus the Company has no specific request of the Commission in this

10 regard at this time."8
11
12 It appears from Ms. Grow's prefiled direct testimony that Idaho Power believes the question
13 should be answered by the Legislature, as suggested by Mr. Sterling. Thus, it appears as though
14 both Mr. Sterling and Ms. Grow concur that the Legislature may be the proper place to answer
15 this most fundamental of questions.
16 Q. DO YOU KNOW IF THE IDAHO LEGISLATURE HAS ADDRESSED THIS
17 QUESTION?

18 A. I know that the Idaho Legislature had a bill before it in the last session that addressed this
19 issue and that Idaho Power, Avista and Rocky Mountain Power were listed as the primary
20 contacts for that legislation. Attached as Exhibit 507 is a copy of the Statement of Purpose and

21 Senate Bill 1364 entitled:
Direct Testimony of Lisa Grow, Idaho Power, p. 14, GNR-E- 11-03.
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1 RELATING TO THE PUBLIC UTILITIES COMMISSION; AMENDING CHAPTER 5,

2 TITLE 61, IDAHO CODE, BY THE ADDITION OF A NEW SECTION 61-542,

3 IDAHO CODE, TO DEFINE THE AUTHORITY OF THE PUBLIC UTILITIES

4 COMMISSION AND ITS JURISDICTION OVER THE ENVIRONMENTAL

5 ATTRIBUTES OF PUBLIC UTILITY REGULATORY POLICIES ACT QUALIFYING

6 FACILITIES AND TO PROVIDE FOR USE AND IMPLEMENTATION OF

7 ENVIRONMENTAL ATTRIBUTES; AND DECLARING AN EMERGENCY.
8
9 So, apparently Ms. Grow was correct that the Idaho Legislature was going to address the
10 ownership of RECs. The bill was referred to a Senate Committee and no action was apparently

11 taken on it as shown on attached Exhibit 508, the "Final Bill Status" report of the 2012 Idaho

12 Legislature.
13 Q. WHAT DO YOU MAKE OF THE FACT THAT IDAHO POWER DECLINED TO
14 ADDRESS REC OWNERSHIP BECAUSE IT THOUGHT THE LEGISLATURE WAS
15 GOING TO DO SO, COUPLED WITH THE FACT THAT THE STAFF BELIEVES
•16 THAT THE LEGISLATURE MAY BE THE BEST PLACE TO ADDRESS REC
17 OWNERSHIP?

18 A. Well, it is all quite confusing. I am sure Idaho Power would have liked the Legislature to
19 pass its REC bill - but it didn't. I can also see why it would have preferred the Legislature to
20 address the question given the PUC Staff's prior, very strong comments that RECs belong to the

21 developers.
22 Q. THE PUC STAFF HAS PREVIOUSLY TAKEN THE POSITION THAT RECs
23 BELONG TO THE DEVELOPERS?
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1 A. Yes, and on more than one occasion. The Staff has filed unequivocal comments with the
2 Commission arguing that RECs belong to the developers of QF projects. In IPC-E-04-02 Idaho
3 Power had asked the Commission to grant it a right of first refusal to RECs in the PURPA QF
4 context. In response the PUC Staff filed comments that provided:

5 Staff recommends that the Commission issue a declaratory order stating that
6 mandatory purchases from QFs under PURPA do not convey ownership of any
7 marketable environmental attributes. Accordingly, any environmental attributes

8 associated remain with the QF. Staff further recommends that the Commission

9 deny the Company's proposal to require that QF developers from whom Idaho

10 Power purchases energy grant Idaho Power a 'right of first refusal' to purchase

11 the environmental attributes associated with the QF facility.9
12
13 The rationale was based on a legal argument that I am not prepared to address; suffice it to say
14 that the Staff was concerned about something in the U.S. Constitution regarding taking people's
• 15 property without compensation. In IPC-E-04- 16 Staff filed comments in response to Idaho
16 Power's request for a Commission order exonerating them from any ratemaking penalty for its
17 waiver of environmental attributes in a PURPA contract. Once again, the Staff filed comments
18 that strongly and unequivocally asserted that environmental attributes belong to the developer:

19 Staff incorporates its related comments filed in Case No. IPC-E-04-02 as if

20 expressly set forth herein and includes same as attachment to these comments. In

21 those attached comments, Staff stated its belief that neither PURPA nor Title 61

22 of the Idaho Code gives the Commission jurisdiction over environmental

23 attributes. Staff recommended that if the Commission determined that it has

24 jurisdiction, that the Commission issue a declaratory order stating that mandatory

25 purchases from QFs under PURPA do not convey ownership of any marketable

26 environmental attributes. Accordingly, Staff recommended that any

27 environmental attributes remain with the QF.'°
Comments of the Commission Staff, Case No. IPC-E-04-02, p. 8.
10 Staff Comments, Case No. IPC-E-04- 16, August 13, 2004 at p. 4 (underscoring added).
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•1
2 I am not a lawyer, but I don't think it is a mere coincidence that the underscored portion of the
3 above quote is the exact same Idaho Code Title that Idaho Power's proposed legislation was
4 proposed to amend and to which Ms. Grow's testimony obviously referred.
5 Q. IT SEEMS SOMETHING MUST HAVE CHANGED TO HAVE STAFF NOW
6 TAKING SUCH A DIFFERENT POSITION ON REC OWNERSHIP IN THE PURPA
7 CONTEXT?
8 A. One would think so, but Staff's testimony suggests otherwise. Why else would they
9 preface their REC ownership testimony with the identification of the "need for the Commission,
10 the Legislature, or the courts to determine REC ownership?"
11 Q. YOU STATED YOU HAD TWO PROBLEMS WITH STAFF'S TESTIMONY
•12 NOTED ABOVE. YOU HAVE ADDRESSED THE FIRST, REC OWNERSHIP; WHAT
13 IS THE SECOND ISSUE?
14 A. Staff's underlying reasoning, that IRP's value RECs, might have been valid if the value
15 of any environmental attributes were in fact included in the computation of avoided costs.
16 According Idaho Power's 2011 Integrated Resource Plan,
17 The value of RECs is not included in the levelized cost estimates but is accounted
18 for when analyzing the total cost of each resource portfolio.
19
20 Therefore, the value of RECs is not part of the calculation of the levelized cost of the Company's
21 generation plant. The value of RECs enters the portfolio analysis only after levelized costs are
"Idaho Power 2011 IRP,p. 72.
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0 1 found. The IRP methodology that is proposed by Idaho Power, as well as the other utilities, to
2 find avoided costs is focused on the determination of levelized costs and hence avoided cost
3 calculations do not include compensation for the value of RECs. As I stated in my direct
4 testimony, the avoided costs in Idaho compensate the QFs only for energy and capacity, and I
5 continue to recommend the ownership of RECs remain with the QF.12
6 Q. MR. STERLING RECOMMENDS THE USE OF A PEAKER (SCCT) FOR THE
7 CAPITAL COSTS RATHER THAN A BASE LOAD GAS-FIRED GENERATION UNIT.
8 WHAT WAS HIS RATIONALE FOR THIS CHANGE?
9 A. Mr. Sterling concludes that an SCCT can be considered a capacity-only resource... He
10 argues that because the SCCT is the least cost capacity-only resource, it better matches a QF's
11 performance. According to Mr. Sterling, a QF cannot be counted on to provide power during the
12 utilities' system peaks:
13 SCCTs are generally added to utilities' resource portfolios to satisfy
14 capacity-only needs, and are usually the least cost capacity resource available.
15 Therefore, the cost of an SCCT can reasonably be considered a capacity-only
16 cost. Utilities that add CCCTs to their portfolio do so because they have a need
17 for both capacity and energy, thus the cost of a CCCT can be considered both a
18 capacity and energy cost. CCCTs, because they are more efficient, generate
19 energy at a lower variable cost than SCCTs, but the tradeoff is that they are more
20 costly to construct.
21 Under the methodology as proposed by the utilities, capacity and energy
22 values are being calculated independently. Therefore, I maintain that the proper
23 resource to use as the basis for computing capacity value is the lowest cost
24 resource that could be added to provide capacity equivalent to what would
'2 DfrCCt Testimony of Don Reading, Joint Parties, p. 59, GNR-E- 11-03.
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1 otherwise be provided by the QF. I believe that using a SCCT is probably most

2 appropriate because it represents the lowest cost, nearly capacity-only resource.13
3
4 The optimal generation expansion path for a utility is to add a resource that meets the system
5 needs at least cost. When the system requires smaller resource additions to meet growing
6 demand, the optimal path is generally a peaking unit that has low capacity costs but at a trade-off
7 of higher running costs. These peaking units would be added until they ceased to be the least cost
8 resource, i.e. when their lower capacity and higher energy costs began to exceed the base load
9 CCCT's higher capacity costs and lower running costs. Therefore, for a least cost growth path, a
10 SCCT contributes more to the system than just capacity. As I stated in my direct testimony, all

11 three of the utilities have either recently added or will soon add a CCCT to their resource stack. 14

12 Therefore, a CCCT is a more logical choice to use for the calculation of long-run avoided costs.
13 Q. DOES MR. STERLING SUPPORT IDAHO POWER'S PROPOSED SCHEDULE
14 74 THAT WOULD ALLOW THE UTILITY TO CURTAIL QFS FOR ECONOMIC
15 REASONS?

16 A. Yes. His reasoning for support of Idaho Power's curtailment tariff is based on the same
17 flawed logic presented by Idaho Power witness Tessia Park in her direct testimony. He also
18 agrees with Idaho Power that the curtailment provisions apply not only to QF contracts going

19 forward but also existing contracts.

20 Q. Idaho Power proposes that Schedule 74 apply to all QF facilities, both existing

21 and new, that have Generator Output Limiting Controls (GOLCs) installed. Do
13 Direct Testimony of Rick Sterling, Idaho Commission Staff, p. 17, (JNR-E- 11-03.
14 Direct Testimony of Don Reading, Joint Parties, p. 9, GNIR-E- 11-03.
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1 you believe that, if approved, the Company would have the authority to apply the
2 proposed tariff to existing facilities whose contracts were in place prior to the new
3 tariff being adopted?
4 A. Yes, I do. As explained by Idaho Power witness Tessia Park, FERC rules at 18
5 CFR 292.304(f) includes a provision that relieves utilities from an obligation to
6 purchase during any period which, due to operational circumstances, purchases
7 from QFs will result in costs greater than those which the utility would incur if it
8 13 did not make such purchases, but instead generated an equivalent amount of
9 energy itself. Because this is a part of FERC rules, I think Idaho Power has
10 always had that authority whether or not it is expressly spelled out in a contract or
11 a tariff. 15
12
13 Since I discussed the problems with Ms. Park's analysis that Mr. Sterling relied on in my direct
14 testimony I will not repeat them here. However, Mr. Sterling does not factor into his reasoning
15 the chilling effect such a provision would have on a QF's ability to gain financing. He also does
16 not seem to see the potential legal problems that could arise through attempting to alter existing
17 signed and Commission-approved contracts.
18 Q. COMMISSION STAFF PROPOSES THE MAXIMUM LENGTH OF A QF
19 CONTRACT BE REDUCED FROM THE CURRENT 20 YEARS TO FIVE YEARS
20 SUPPORTING IDAHO POWER'S PROPOSAL FOR PROJECTS USING THE IRP
21 METHODOLOGY, WHILE SMALLER PROJECTS USING THE SAR
22 METHODOLGOY WOULD REMAIN AT TWENTY-YEARS UNDER STAFF'S
23 APPROACH. WHAT COMMENTS DO YOU HAVE ABOUT THE LOGIC OF MR
24 STERLINGS POSITION?
25 A. Mr. Sterling outlines the history of the Commission's decisions that have adjusted the
15 Direct Testimony of Rick Sterling, Idaho Commission Staff, GNIR-E-1 1-03, pp. 37 - 38.
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0 1 contract length from its original 35 years down to 20 years, down again to five years, and then
2 back up to 20 years. He contends that reducing the contract length to five years would not
3 adversely impact QF development. As part of his justification he discusses QF development
4 during the 68 month period when contract length was limited to five years.

5 Q. During the approximately five and a half year period when contract length
6 was limited to five years (September 1996 through May 2002), how many
7 PURPA contracts were signed?

8 A. There was only one PURPA contract signed in Idaho during this time frame.

9 However, at the time, the eligibility cap for published rates was also limited to

10 facilities one megawatt or smaller. In addition, published rates were also quite

11 low, primarily due to low natural gas prices. Furthermore, most PURPA hydro

12 and cogeneration projects had already been developed, while wind, solar and

13 biogas technologies had yet to fully develop. The combination of all of these

14 factors, not shortened contract length alone, caused very few PURPA projects to

15 be developed in Idaho during this time period. 16
16
17 He is correct that the 1 MW cap would impact the number and momentum of QF developments;
18 however, currently gas prices are lower than they were during that period, and a major fact that
19 wind, solar, and biogas were not being developed was due to the shorter contract length that
20 prevents QFs from obtaining financing.

21 He dismisses the significant impact on financing of QF projects by limiting them to only
22 a five year contract.
23

24 Q. Do you believe that the Commission has a responsibility to ensure contract

25 lengths are long enough to enable QFs to obtain financing?

26 A. No, not necessarily. Long-term contracts have been used by the Commission in

27 the past to boost development of PURPA projects. However, circumstances have

28 changed. It would be contrary to the public interest to encourage PURPA
16 Ibid., pgs 27, 28.
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I development at a time when it is not needed to serve customers and at a time

2 when poor economic conditions strain customers' ability to pay. I believe it would

3 be good public policy for the Commission to use effective tools, such as limiting

4 maximum contract length, to control the pace of PURPA development. 17
5
6 Mr. Sterling apparently does not believe the Commission, under PURPA, has to provide
7 contracts long enough that QFs can find financial backing. However, according to Idaho Power
witness Mr. Hieronymus, one of the mandates of PURPA is to encourage cogeneration and small
9 power production.

10 Section 210 tasked FERC to devise rules that "it determines necessary to

11 encourage cogeneration and small power production and to encourage geothermal

12 facilities of not more than 80 megawatts capacity."8
13
14 As I stated in my direct testimony, "Limiting PURPA contract terms to five years would preclude

15 the vast majority of QF developers from being able to secure financing for their projects" and thus

16 would be discouraging rather than encouraging QF development.19 Mr. Sterling also believes that

17 shortening the contract length to five years would "control the pace" of PURPA activity in Idaho. As

18 pointed out above and in my direct testimony, adopting Mr. Sterling's positions and the utilities'

19 proposal in this case will essentially kill PURPA development. The loss of tax credits and renewable

20 power incentives at both the state and federal level, in combination with current low gas prices, will

21 already stop or at a minimum significantly slow QF development in Idaho. Imposing a set of policies

22 aimed at stifling QF development, thus merely represents 'insult to injury" to the QF industry
17 Ibid., pgs 28, 29.
'8 Direct Testimony of William Hieronymus, Idaho Power Company, GNR-E- 11-03, p. 18.
19 Direct Testimony of Don Reading, Joint Parties, GNR-E- 11-03, p. 46.
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1 Q. ARE THERE ADDITIONAL REASONS COMMISSION STAFF GIVES IN
2 SUPPORT OF REDUCING QF CONTRACT LENGTH TO FIVE YEARS?
3 A. Mr. Sterling contends that ratepayers' fuel cost risks are lower for a utility-owned
4 resource than for PURPA projects.
5 Fuel costs associated with utility-owned resources are also passed on to
6 customers, partly through base rates and partly through PCAS. However, fuel
7 costs are tracked annually and rates are adjusted accordingly. Consequently, while
8 customers are exposed to fuel price risk for both PURPA and utility-owned
9 resources, the annual adjustment of rates for Utility-owned resources exposes
10 customers to less risk for utility-owned resources than for PURPA resources.
11 Moreover, recovery of costs for utility-owned resources is not guaranteed.
12 However, as previously stated, once a PURPA contract is approved by the
13 Commission, customers are obligated to pay 100 percent of the costs. 20
14
15 I am assuming when he says, "the annual adjustment of rates for Utility-owned resources
16 exposes customers to less risk for utility-owned resources than for PURPA resources" he
17 believes that the power supply costs that are passed on to customers annually will be lower than
18 the those found in signed PURPA contracts. As I stated in my direct testimony, natural gas prices
19 have been historically very volatile. When a utility's natural gas plant is approved and put into its
20 rate base, its customers will annually be responsible for whatever the prices may be, whenever
21 they may occur, over the life of the plant. Only if one assumes that natural gas prices will remain
22 at their current low levels indefinitely into the future can you conclude that customers will pay
23 less for generation from a utility gas resource than a PURPA project.
24 Mr. Sterling also states that the cost recovery for utility-owned resources is not
20 Direct Testimony of Rick Sterling, Idaho Commission Staff, GNIR-E- 11-03, p. 31.
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1 "guaranteed." In a strict theoretical sense, I would agree that regulation does not 'guarantee'
2 recovery, but rather gives the utility the 'opportunity' to earn its approved rate of return.

3 However, as a practical matter, the utilities usually do fully recoup their investment in a
4 generation plant. For example, in the case of Idaho Power's Langley Gulch Plant, the
5 Commission did essentially 'guarantee' the Company it would be able to recover its investment
6 when it approved a certificate to build the plant. Even if, for example, the plant were to
7 experience a temporary outage, the utility would continue to earn its 'unguaranteed' rate of
8 return on the temporarily out-of-service investment. In contrast, , a PURPA project is afforded
9 no such benefit, and only earns revenue when it is able to deliver power; therefore, when
10 unforeseen problems knock the QF offline, QF owners are not able to recoup their investments

11 for lost generation.
10 12 Q. WHAT IS YOUR RESPONSE TO DR. MCHUGH'S OPINION ON THE FIRST
13 YEAR DEFICIT APPROACH ADVOCATED BY THE UTILITIES?

14 A. Dr. McHugh is advocating for the Staff to reverse itself and reinstate the first year deficit
15 approach in the calculation of avoided cost rates offered to PURPA projects. She reviews Staffs
16 nine areas of concern when they recommended it be abandoned several years ago. She explains
17 why some of the reasons are no longer valid and offers a new method of calculating the first year
18 deficit based on both capacity and energy. She goes on to state the rationale for reinstating the

19 first year deficit was 'sound':

20 Q. Why was the "first deficit year" concept abandoned?
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1 A. At the time this was abandoned, Staff expressed concerns that determining the

2 first deficit year was problematic even though the underlying rationale for it was

3 sound.21
4
5 As I pointed out in my direct testimony, this means a utility acting prudently to meet its demand
6 should always be in surplus; however, reducing avoided cost payments to PURPA projects for
7 these surplus periods does not represent the proper calculation of the avoided cost for the utility
8 in the long-term. I certainly disagree with her conclusion that the underlying reasoning for the
9 first year deficit is sound. It is interesting that she agrees with and quotes Avista witness Mr.
10 Kalich when on page 21, lines 5 through 9 of his direct testimony he states,

11 It is not fair to pay one resource with a low capacity factor and an equivalently

12 high on-peak contribution the same per-MWh payment as second base load plant

13 operating with a relatively high capacity factor all year round. Using the method,

14 the low capacity factor resource would receive much lower total compensation

S
15 even though the resource provided the same on-peak capacity benefit to the

16 utility. 22
17
18 However as I pointed out in my direct testimony Mr. Kalich also says,

19 It is often true that utilities are surplus in early years; being so is an essential part

20 of providing reliable utility service. It also is true that QF developers would be

21 affected by these surpluses were they to receive lower early-year _payments during

22 surplus years. But this effect is a reflection of true avoided costs.2
23

24 I strongly disagree that paying QFs lower early-year payments accurately reflects of "true avoided

25 costs." It is not true that by implementing the first deficit year, and thereby denying QFs capacity
21 Direct Testimony of Cathleen MChugh, Idaho Commission Staff, GNR-E- 11-03, p. 7. Emphasis in original.
22 Ibid pgs 10, 11.
23 Direct Testimony of Avista Witness Clint Kalich, GNR-E- 11-03, pp. 1 3-14.
Reading Rebuttal
Clearwater, Simplot, Exergy
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1006

1 payments in the early years, accurately reflects a utility's own generation plant. This is so because

2 the utility receives full recovery of its capacity costs for the entire life of the plant - including the

3 early years.
4 Q. DR. READING, DO YOU HAVE ANY CONCLUDING COMMENTS?
5 A. As I pointed out above there are numerous other positions taken by the Commission Staff
6 in their testimony that I have already dealt with in my direct testimony that I continue to oppose.
7 It is for the sake of brevity that they have not been addressed in the above rebuttal testimony.
8 The Commission Staff in their direct testimony consider a wide range of issues dealing with the
9 implementation of PURPA in Idaho and make recommendations on each aspect. It appears that if
10 one were to put Staff's recommendations into two categories, one labeled pro-QF development

11 and the other anti-QF development, virtually all would fall in the anti-QF development category.
1012 A plainly stated purpose of PURPA law is to 'encourage' independent power production. Taken

13 together could lead one to conclude that Staff is strongly anti - if that is the case it is opposed to
14 federal law and in my mind not in the public interest. If Staff's recommendations were adopted,
15 as said in my direct testimony, it would be "PURPA-killing." It would be difficult for the
16 industry to rebuild itself and contribute to electric system needs in any cost effective manner
17 Q. DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY ON JUNE 29,2012?

18 A. Yes it does.
Reading Rebuttal
Clearwater, Simplot, Exergy
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1007
0 1 (The following proceedings were had in
open hearing.)

3
MR. RICHARDSON: And I'll ask that Dr. Reading's

4
Exhibits 501 through 507 (sic) be marked for identification

5 purposes.

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COMMISSIONER SMITH: Seeing no objection, the

7 exhibits will be.

8
(Clearwater Paper Corporation, et al,

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Exhibit Nos. 501-508 were premarked for identification.)

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MR. RICHARDSON: Thank you, Madam Chair. We have

11 no preliminary matters. Dr. Reading is available for cross-

12 examination.

13 COMMISSIONER SMITH: Thank you, Mr. Richardson.

14 Any questions, Mr. Miller? Mr. Uda?

15 Mr. Williams. Mr. Arkoosh is gone.

16 Mr. Otto.

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MR. OTTO: No questions, Madam Chair.

18 COMMISSIONER SMITH: Ms. Nelson.

19
MS. NELSON: No questions, Madam Chair.

20 COMMISSIONER SMITH: Mr. Solander.

21 MR. SOLANDER: Yes, please.
22
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0 1 CROSS-EXAMINATION
BY MR. SOLANDER:
Q. Good afternoon, Dr. Reading.
A. Good afternoon.
Q. You state in your testimony on page 61 of your
direct that you believe a QF contract and tariff would be
useful?
A. You're referring to which line?
Q. It is line 4, beginning on line 4, on page 61.
A. Yes.
Q. And do you agree generally that aside from a few
of the response periods that are included in Rocky Mountain
Power's proposed Tariff 38 that you I believe said are too
long, do you believe that it's a reasonable approach?
A. I believe the -- it is a reasonable approach to
establish the -- you know, the conditions that the -- the
philosophy of Schedule 38, I certainly agree with.
MR. SOLANDER: Thank you. I have no more
questions for Dr. Reading.
COMMISSIONER SMITH: Ms. Sasser, do you have
questions?
MS. SASSER: I do. Thank you, Madam Chair.
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CROSS-EXAMINATION
BY MS. SASSER:
Q. Good afternoon, Dr. Reading.
A. Good afternoon.
Q. Nice to have you with us.
A. You don't know how nice it is to be with you.
Q. I'll be gentle.
A. Yes.
Q. You generally testify that $45 a kilowatt hour is
excessive for liquidated damages. Is that correct?
A. I would have to review my testimony. I can't
recall the $45 necessarily being excessive. I think it's
arbitrary and unnecessary.
Q. Okay. Do you believe the 45 kW is excessive
then?
A. The $45?
Q. $45 a kW.
A. Yes. Yeah, it -- my position is, when you read
my testimony, is that it -- liquidated damages should be based
on what damages actually could be or would be.
One of the things I find curious looking at
the -- excuse me -- $45 liquidated damages is that all three
Utilities have that and they have the same thing for all the
different types of QFs, yet one of the major points of IRP
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impose different types of costs on the Companies. So just to

3 pluck $45 out and say that's it I think is not the proper

4 approach.

5
Q. Okay. Isn't it true that if market prices far

6 exceed avoided cost rates the way that they did in, say, early

7
2000, 2001, that actual damages for a Utility could far exceed

8 the 45 kW?

9 A. Potentially, yes, but that would be decided once
10 whatever breach is -- whatever the lawyers come to on whatever

11 the breach is, and then determine what the actual property loss

12 would be.

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Q. Okay. So for my own clarification then, it is
IEU only your testimony that $45 kW is arbitrary, but not excessive

15 necessarily?

16 A. Depends on the circumstances.

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Q. Okay. Fair enough. What obligation does a QF

18
facility have to perform if their liquidated damages happen to

19 be zero?

20 A. They don't get any revenue and can't pay the bank
21 back. They -- a QF only gets paid when they supply power to

22 the Utility.

23 Q. Would it be fair to allow a Utility to delay a

24 QF's online date without penalty if it were in the Utility's

25 best interest?
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A. You need to tell me more.
Q. What I'm getting to is if -- if the argument by
the QF industry is that the Utility is not suffering any harm
by them not coming online --
A. Okay.
Q. -- then does the Utility get that same argument
against the QF?
A. I believe my position is not that the Utility is
not having -- not experiencing any harm by a QF not coming on.
My testimony says that those damages should be specific. And
so I would, depending on the QF and what happened and what
prices in the market is, et cetera, et cetera, and I would turn
the coin over equally and say I don't think the Utilities would
be shy at all about coming after their -- you know, what would
be in their best interests. They have the same understanding,
it's the same rules. It should be actual property damage after
whatever the cause is.
Q. Okay. If you can turn to page 50 of your direct
testimony, you --
Are you there? I'm sorry.
A. Yes, I am.
Q. Okay. You speak about the current wind
integration charge and its consideration of curtailment
circumstances being included in that charge. Is that correct?
A. Correct.
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Q. Can you explain how the wind integration charge
accounts for low load conditions here in Idaho?
A. The -- the theory behind what I have in that
section of my testimony is that wind integration charges are
charged because it's an intermittent resource. To me, that
implies that the -- you know, whatever load conditions happen
to be, that the 6.50 should, in part, account for that.
Q. If you turn a couple pages to page 52 and 53 of
your direct testimony --
A. Yes.
Q. -- you continue to address the circumstances
under which you believe that FERC would allow curtailment?
A. Okay.
Q. And you describe a scenario under which FERC
Regulations would apply. I'm looking for the line.
You say if slow ramping base load units had to be
backed down during light load periods and the only way for the
Utility to meet its next peak is with more expensive peaking
resources such as that of a less efficient gas peaking unit,
you surmise that, and I quote, "This does not appear to apply
to Idaho Power for several reasons." And that's your
testimony?
A. Yes.
Q. So would you agree then that if this Commission
finds that that scenario that you give does apply to Idaho
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Power, that Schedule 74 and the FERC Regulations then are
consistent?
A. Without -- you're making me tread lightly here.
There have been I wouldn't say "numerous," but "various"
Commissions through time have come to conclusions that, after
they come to those conclusions, I still don't agree with.
Okay.
And my -- my theory of this whole section is --
and I might throw in that I'm one of numerous nonlawyer
witnesses opining on close to legal ground -- that what FERC
says it's for -- operational problems, that, you know, system
reliability, those kinds of issues - is where it would apply,
but it wouldn't apply for, you know, back on more familiar
territory where I am, economic reasons.
Q. On page 66 of your direct testimony, beginning at
line 6, you state --
A. I'm not quite there yet.
Q. Okay.
A. Yes.
Q. You state that under existing Idaho precedents,
QFs are almost always responsible for the network transmission
upgrades required to deliver their energy. Do you see that?
A. Yes.
Q. With the exception of the Cassia group, which I'm
sure you're aware of details on, how many QF are you aware of
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Idaho?
A. I would have to go back and look. I did not have
a list in front of me, but based on my experience over time
listening to developers tell me what the situations were. I do
not have a list.
Q. Okay. Are you aware then, of those that may have
been required to pay, how many were subject to a 100 percent
refund?
A. No.
Q. Last question: If you reference page 2 and 3 of
your rebuttal testimony --
Tell me when you're there.
A. Yes.
Q. -- you state that Mr. Sterling's position on REC
ownership is PURPA killing. Is that correct?
A. That is correct. That is one of the elements
that I see in this case that Staff's position has taken which,
as a whole, would be PURPA killing, if you --
Q. So do I read that incorrectly then?
A. No. I think it's -- it certainly could be the
straw that breaks the camel's back. I guess that would be my
best way to put it.
Q. Okay. Isn't it true that PURPA does not address
RECs or RECs' ownership?
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A. That is correct.
Q. Then prior to RECs coming into existence, were
there viable QFs that built and produced and completed projects
in a financially responsible and beneficial manner?
A. Without being too snide from the Utilities'
perspective, but obscenely high prices so that may have been
the reason.
Let me explain a little bit my position of RECs,
again a lot of opining of nonlawyers on the legality and what
FERC says and doesn't say.
My view on RECs from an economic perspective is
they're a by-product. And what I mean by a by-product is -- is
that an entity produces X to sell it in the market and
sometimes there is a by-product as a result of that production.
What -- put my professor hat on for a sec.
I did a water rights case for Jerome Cheese,
asked the plant manager, you know, What's your economic, what's
your business model?
And he said that Kraft will buy every pound of
cheese we can produce, no problem with milk.
And I said, Oh, well, that's great, you're making
a ton of money.
He said, No, we don't make money -- we make
money, but our big profit is -- is the whey. And the whey has
proteins and whatever it is they can put in feed.
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So, to me, saying that the Utility gets the RECs
because it buys the electricity would be equivalent to Kraft
going to Jerome Cheese and saying, You have to give us this
valuable by-product because we buy all the cheese.
That, from an economic perspective, it's clear to
me that RECs are a by-product and therefore --
Q. But so as I understand your answer in your
example, QFs are viable and make money just producing the
energy, but the big money is in the RECs?
A. You're stretching the example. I was trying to
explain --
Q. I'm sorry, that's what I heard.
A. Nice try, Ms. Sasser.
-- that it was an example of a by-product.
Q. But there were -- the question more precisely
was: There were viable QF5 built and completing contracts
prior to the creation of renewable energy credits?
A. Yes. And some were profitable and some had
troubles.
MS. SASSER: Okay. That's all I have, thank you.
COMMISSIONER SMITH: Thank you.
Mr. Andrea.
MR. ANDREA: Thank you, Madam Chair.
COMMISSIONER SMITH: You also need to get closer
to your mic. Thank you.
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CROSS-EXAMINATION
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3 BY MR. ANDREA:

4
Q. Good afternoon, Dr. Reading.

A. Yes.

6 Q. I want to follow up, to start, on a couple of

7
questions that Ms. Sasser asked. I just want to make sure I

8 understand your testimony.

9
Did I understand you to say that damages should
10 be decided at the time of the breach based on market prices for

11 power and other factors? Is that correct?

12 A. I would think would be a significant element, but
.
13 the damages, you know.

14 Q. Okay.

15 A. Your profession make their money going into the
16 hearing rooms and determining a wider band of those kinds of

17 things. So certainly the price of power would be one, but a

18 breach potentially could cause other damages.

19 Q. Okay. Fair enough.

20 A. It's a position the Utilities have taken.

21 Q. Sure. And did I also understand you to say that
WM depending on what the market price for power was at the time of
23 the breach, a $45 per kW damage would not necessarily be

24 excessive?
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Q. If a QF executes a power purchase agreement with
a Utility, say, five years before its commercial online date
and they don't make that commercial online date, at the time
that the contract is entered is there any way to accurately
predict what those market power prices will be five years down
the road?
A. Not accurately. We all project it, I mean, it's
what we do, but often incorrectly.
Q. In your experience working with QFs, has it been
your experience that some, maybe not all, but some QFs do not
have substantial balance sheets that could cover, say, $45 per
kW damage?
A. Well, if you don't -- I would like to clarify the
question. The question you're asking is -- is that some Us
don't have the financial wherewithal to be able to come up with
that $45 a kW payment, originally, and one of the points I make
in my testimony is --
Q. I'm sorry, Dr. Reading, that was not my question.
A. Okay.
So let me restate and maybe I can make it a
little more clear.
A. Certainly.
Q. Really my question was isn't it true that some
QFs do not have the financial wherewithal to pay for damages at
the time of breach. I'm not talking about whether they have
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the wherewithal to post the security; I'm ask asking whether

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they, in the absence of security, would have the financial
3 wherewithal to pay those damages should they occur.

4 A. You mean, five years down the road, what's their

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financial condition?

6 Q. And in your experience, isn't it true that some
7 Us do not have a significant enough balance sheet to pay those

8 damages?

9 A. Let me answer it this way: I cannot think of one

10 specifically, but hypothetically and theoretically as an

11 economist, I could certainly imagine that situation.

12
Q. Okay, thank you very much, Dr. Reading. I'll

.
13 move on to a different subject. You've got your testimony up

14 there with you. Correct?

15 A. Yes.

16
Q. Okay. I'd like to direct your attention to
17 page 7 of your direct testimony. And let me know when you're

18 there.

19 A. I am there.

20
Q. Okay. Starting on line 7, you state that the SAR
21 methodology has been robust through all of those changes, and
WM has produced avoided cost rates that have proven to be

23 remarkably accurate in hindsight. Is that correct?

24 A. That is correct.

25
Q. And when you talk about "through all of those
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three-decade time frame. Is that right?

3 A. Yeah, count. Thirty years. I guess we are. If
not, it's close.

5 Q. I'm just looking at lines 3 and 4 on the same

6 page.

7 A. Okay.

8
Q. It says Idaho's energy --

9 A. Okay, I say "three decades," yes.

10
Q. Three decades. When you say that the SAR has
11 produced avoided cost rates that have proven to be remarkably

12 accurate, what do you mean, remarkably accurate as to what?

13 A. As to mimicking what the long-run avoided cost of

14 the Utility is based on the fact that that's what it would cost

15 them to build their next resource.

16
Q. Okay. So in preparing this testimony, did you go

17
back and review all of the published avoided cost rates over

18 that 30-year period?

19 A. No, but I'm generally -- I was here, I was on the
20 Commission Staff when PURPA started, so I'm generally familiar

21 with the history of avoided cost rates.

22 Q. Okay. Did you perform any analysis to determine

23
the accuracy of those rates as compared to a Utility's avoided

24 cost, as you describe them?

25 A. No, I performed no analysis of that.
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Q. So it's fair to say you base that statement on

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3 A. On 30 years' experience about playing in this

4 sandbox, you know.

5 Q. Okay. Thank you, Dr. Reading.

6
Can we move to page 15 of your direct testimony.

7 Let me know when you're there.

8 A. I am there.

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Q. On page 15, just speaking generally, you take

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issue with what you state is Mr. Kalich's assumed definition of

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"true avoided cost." Is that fair to say?

12 A. Yes.
.
13 Q. What is your understanding of what true avoided

14 cost means?

15 A. As I hoped to explain in my testimony, true
16 avoided cost would be what it costs the Utility to provide

17 power over a arbitrarily 20-year period. Otherwise, if a

18
Utility is out building its own resources, be it a gas plant or
19 a coal plant or a hydro dam or whatever, the avoided cost would

20 then be what that next viable unit would be for that particular

21 Utility.

22
Q. Okay. Is it your view that QFs should be

23 compensated for, and that avoided cost rates should include

24 compensation for, capacity that the QF's resources does not
25 provide or for that the capacity that the Utility does not
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A. Certainly, I can answer the second part: What

3 kind of a QF would not provide capacity?

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Q. Hypothetically, you could -- for example, a

5 summer-peaking Utility, perhaps a canal drop, may not provide;
6 or winter-peaking Utility, a canal drop may not provide

7 capacity. There are resources that may fit that description.

8 A. And, theoretically, we would have to go into it.

9
I am not opposed to seasonality in rate

10 structures. What I am opposed to is the theory that the

11 sufficiency period or that there should be no capacity payment

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in the -- in -- during periods of surplus for a Utility. And I

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find it curious in this docket where folks are saying let's

14 move the -- Mr. Kalich's statement that Utilities are often

15 surplus in the short run.

16 My opinion is -- is that it's probably more than

17 some of the time, it's probably most of the time.

18 And I would add that if a Utility is doing what

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it should be doing, it's always surplus in the short run
20 because investment is lumpy. And I don't want to go into all

21
kinds of a lecture here, but I think I quoted out of the Grey

22 Book, et cetera, when you have lumpy investment that you're

23 always going to have a surplus period, so that if you have a

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Q. Give me just a second, Dr. Reading. Thank you.

3 So, Dr. Reading, if a QF has the ability to come

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in and sign a contract as early as five years before their

5 expected commercial operation date, doesn't that substantially
6 eliminate the problem of Utilities being surplus in the short

7 run and actually provide more of an opportunity for the QF to
8 be compensated for its capacity earlier in the contract term?

9 A. I guess I don't track you. Your logic escapes

10 me, so give it to me again. And I'm not saying it's you; I'm

11 saying I didn't track the question.

12
Q. That's fair enough. Please always ask for
.
13 clarification. I'll be happy to try.

14 If the QF comes in and signs a contract five
15 years before its expected commercial operation date and that
16 Utility begins to plan for that resource to be part of its

17 system, doesn't that substantially mitigate the potential for

18 QF5 to not be cooperative, to be compensated for capacity at

19 the beginning stages of the contract?

20 A. I would need to answer that by saying it depends

21 on when the price is locked in. Because when the Utility
rerm offers a QF a avoided cost price, they calculate that -- at

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least what's being proposed in this docket -- they do that,

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2 wouldn't be getting capacity payments for that surplus period.

3
Q. Okay. Thank you. And I just want to hopefully

4 get a really quick, short answer on the first part, because you

5 went to the second part of the question. And I apologize, I

6 should have pulled them apart. And so let's go back to the

7 first part of the question:

8 Is it your view that QFs should be compensated

9 for attributes they do not provide to the Utility, such as

10 capacity?

11 A. If they -- if it -- not necessarily.

12
Q. Okay. Thank you. Can we turn to page 19 of your

13 testimony?

14 A. Yes.

15 Q. On page 19, starting on line 7, you state -- and

16 I'm not quoting you, so tell me if I mischaracterize --

17 generally that you agree that the Commission should use the

18 regularly updated gas forecasts generated by the EIA in its
19 annual outlook report as the forecast for the Commission to use

20 for updates of the published gas SAR avoided cost rates?

21 A. Correct.

22
Q. Is it important, in your mind, to regularly

23 update gas prices using a good forecast for purposes of

24 setting --
7
25 A. A what forecast?
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Q. Is it important, in your mind, to regularly

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4 A. I'm missing it. A what forecast again?

5 COMMISSIONER SMITH: "Good."
6 THE WITNESS: What?

7 COMMISSIONER SMITHS "Good."

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Q. BY MR. ANDREA: "Good."

9 A. Good. Oh. Only if you hire Ben Johnson

10 Associates to do your forecasting.

11 Yes, I would say, given the definition of what

12 "good" is. And I think for something like calculating avoided
.
13 cost, an important -- two important elements is, one, that is

14 from a third party that doesn't have a dog in the fight; and

15 also that it is transparent where everybody can look at it.

16
Q. So gas forecasts are an important element for

17 setting an accurate avoided cost rate?

18 A. Yes.

19 Q. Okay. Can I get you to turn to page 34 of your

20 testimony?

21 A. I am there.

22
Q. Okay. Thank you. On page 34, you have a chart
23 that purports to compare the costs of Langley Gulch compared to

24 calculations of certain resources using the current and
.
25 proposed IRP methodology. Is that correct?
I 1026 I
HEDRICK COURT REPORTING READING (X)
P. 0. BOX 578, BOISE, ID 83701 CPC, et al
A. That is correct.
Q. And correct me if I'm reading the chart
incorrectly, but it said, as I read it, the chart shows a high
of roughly $111 per megawatt for Langley and a low of roughly
$47 for a 20 megawatt base load resource using the proposed IRP
methodology. Is that correct?
A. Yes. And that's Idaho Power's, as I remember,
numbers.
Q. Okay. The $111 number is -- for Langley is based
on a calculation that was done in 2009. Is that correct?
A. Yes, when they came in.
Q. And the $47 number was calculated using the
proposed IRP methodology, but was calculated this year. Is
that correct?
A. About a year ago, yeah.
Q. Okay. So, in 2011?
A. Yep.
Q. In preparing this chart, you didn't make any
adjustment for gas prices, did you?
A. No. I didn't have the ability. I tried to take
some numbers and compare them, and I would have to have had all
of the models up and running and put in whatever gas prices
would be deemed appropriate, and I may well consider a
different gas price appropriate to what the Utility used. I
didn't know exactly what they used.
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Q. But you made no adjustment?

2 A. I made no adjustment, no.

:3
Q. Are you aware that gas prices have changed

4 significantly since 2009?
A. We all are, yes.
6
Q. Okay. So comparing $111 for Langley Gulch 2009

7 prices to the $47 IRP methodology is really -- it's apples to

8 oranges. Correct?

9 A. I would say maybe it's Granny Smiths to Romes.

10 don't think it's completely inaccurate.

11 And one thing in looking at this analysis, which

12 would change at -- let's say for Langley Gulch, it's 65 percent

.
13 capacity factor. A later filing by the Staff, as I remember,

14 said Langley Gulch was only going to run at, like, 40 percent

15 or something. So natural gas prices are a element in

16 explaining the difference in prices, but if we're going to

17 adjust that, I would have to have gone through and adjusted all

18 other kinds of variables that may affect it both up and down.

19
Q. Okay, thank you. Just a couple more -- well, a

20 couple more with several follow-ups, but I'll try and be as
brief as possible.
22
23
24
25
there.
On page 45 of your direct testimony -- can you go
A. Yes.
Q. On this page of your testimony, this part of your
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1
testimony, you point to Avista's Reardan Wind Project as an

2 example of a Utility plant taking longer than two years to

3 achieve online status. Is that --

4 A. Yes.

5
Q. -- generally correct?
6 Are you aware that Avista has at least, for now,

7 decided not to pursue Reardan?

8 A. Yes.

9
Q. So it really isn't fair, the statement, to say

10 Reardan demonstrates it takes longer than two years for a

11 project to come online, does it?

12 A. The point that I was attempting to make by using

13 Reardan -- well, I guess there would be two elements to it:

14 There seems, in my mind, there seems to be a
15 confusion on two years and then comparing it to how long it

16
takes to construct it. If you're building a project, be it

17
hydro or wind or anything, the whole process takes

18 significantly longer than two years. For wind project, you
19 have to put up a tower; for hydro project, you have to worry

20 about environmental constraints. So I talk about the whole

21 block of time.

22 And for Reardan, you said that, for now, that the

23 Utility has decided not to build Reardan. And, I'm sorry, I've
24 missed the other name because you purchased another --

25
Q. We'll talk about that in a minute. Let's just
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focus on Reardan for a moment.
A. Okay. And as I understand the Commission's
Order, you are not collecting from ratepayers but you are
booking both CWIP and AFUDC so that -- and preserving the site,
and so down the road if Avista decides to build it, then I
assume that it would ask the Commission for reimbursement plus
probably missed interest in the interim.
Q. So let's talk about Palouse Wind. You're aware
of our Palouse Wind Project?
A. Just what I've read.
Q. But you're generally aware --
A. Yeah.
Q. -- that Avista has acquired through a PPA
approximately 100 megawatt -- slightly higher than a
100-megawatt wind project?
A. Yes. And my understanding, it was a better deal
than Reardan.
Q. Do you know how long that project is expected to
take to develop?
A. No, I do not.
Q. Would it surprise you to know that Avista issued
the RFP for that project in early 2011?
A. I will accept that.
Q. Would it surprise you to know that that project
is expected to be in commercial operation by the end of this
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HEDRICK COURT REPORTING READING (X)
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.
1 year?
2 A. I will accept that.

3
Q. So in other words, you would accept that it could
4 take less than two years to develop a 100-megawatt wind

5 project?

6 A. Depending on the financing and where you are.

7 You said it's a PPA. I don't know who the developer of the
8 project is and how much front-end time it took them to
9 determine that that was the best place to put it, get their

10 interconnection agreements, those kinds of things.

11 I will accept that two hours from -- I mean, two

12 years on the PPA. What I don't know is what all that front end
13 was from the developer you're purchasing the PPA from.

14 Q. All right. Let's move on to page 31 of your

15 direct testimony.

16 A. Yes.

17 Q. So on page 31 --

18 Are you there, sir?

19 A. Yes.

20 Q. -- starting on line 17, you state: Added to this

21 complexity is the number of variables the Utilities prepare
WM (sic) to make between IRP5 -- "as discussed above," in
23 parentheses -- that are changed at the discretion of the

24 Utilities and do not -- and not properly vetted by the

25 Commission or parties.
I 1031 I
HEDRICK COURT REPORTING READING (X)
P. 0. BOX 578, BOISE, ID 83701 CPC, et al
And there you're talking about the IRP. Is that
correct?
A. Yes.
Q. Are you aware that the IRP process is open to the
public?
A. Certainly.
Q. Have you ever participated in any of the
Utilities' IRP open meetings?
A. I've never been on a board, but I have certainly
sat in numerous IRPs for Idaho Power. I can't think whether
I've ever been to an Avista, but I've certainly been in the
audience during the Idaho Power IRP process.
Q. And you've had an opportunity to comment in those
proceedings?
A. You comment, sure.
Q. Okay.
MR. ANDREA: That's all I have. Thank you.
COMMISSIONER SMITH: Mr. Walker.
MR. WALKER: Thank you, Madam Chair.
CROSS-EXAMINATION
THE WITNESS: Now I'm ready.
Q. BY MR. WALKER: All right. Good afternoon,
Dr. Reading. I'd like to follow up on something that
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HEDRICK COURT REPORTING READING (X)
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Mr. Andrea touched on, and this is found on page 7 --
A. Of direct?
Q. -- of your direct, and also in a general sense
the several pages leading up to seven as well, essentially the
first several pages of your testimony where I know we've had a
lot of talk of Orders and reference to Commission Orders, and
you talk about some old Orders from the '80s and generally
talking about the SAR. And then ultimately on page 7, you have
a statement that Mr. Andrea asks you about where you say the
SAR has produced avoided cost rates that have proven to be
remarkably accurate in hindsight?
A. Yeah.
Q. And did you review any other Commission Orders
perhaps from this case or ones that may be more current than
those that you cited with reference to that particular issue?
A. I certainly have read several Orders with respect
to this case. I believe the Chairman of the Commission -- I'm
trying to -- what case preceded this? Anyway, Madam Chairman
indicated that the Commission had decided that the rates were
out of whack, and therefore we need to have a hearing.
And I might add that -- well, if I may expand a
little: One of the things that I find curious in this case is
that we're talking about avoided cost price. In fact, I think,
Mr. Donovan (sic), you were quoted in the Press-Tribune this
morning as saying this case is about the proper price, and I
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HEDRICK COURT REPORTING READING (X)
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1 assume AP quoted you correctly.

2
If we're just dealing with price and natural gas
3 prices are a major driver and we agree with this, it would make

4 more sense, to me, that the Utilities would come in and say,

5
Hey, wait a minute, given the established methodology, the SAR,
6 that we need to do something about avoided cost prices because

7
they are too high given natural gas prices. And I believe for
8 more than two years that avoided cost prices are out of whack

9 relative to natural gas prices right now.

10 What I found curious about this case is that it

11 should be about price, but price isn't who owns the RECs, price

12
isn't 20 year versus five years. Price isn't interruptibility.

.
13
Those aren't elements that deal with price. And they deal more

14 with, my personal view, the dismantling of the independent

15 power producer producing industry in Idaho, which I think

16 should remain viable in the long run for the benefit of the

17 ratepayer.

18 Q. And, nevertheless, you're of the view that the

19 SAR produces remarkably accurate rates?

20 A. Yep.

21
Q. And are you aware of this Commission's finding

22 of -- in this matter, GNR-E-11-03? This is from Order 32498 in

23 this proceeding issued in March of this year where the

24 Commission specifically found, and I quote: Methodologies

S
25 previously approved by this Commission as utilized and applied
I 1034 I
HEDRICK COURT REPORTING READING (X)
P. 0. BOX 578, BOISE, ID 83701 CPC, et al
1 by Idaho Power do not currently produce rates that reflect
2
Idaho Power's avoided costs, and are not just and reasonable
3 nor in the public interest.
4 A. Yes, and that was what I was referring to about
5 Madam Chairman stating essentially that from the Bench.
6
As I attempted to say a little while ago, that if
7 that is the problem is the price, that is not necessarily the
8 SAR methodology. It is the application, in my opinion, of the
9 SAR that it wasn't maintained to reflect current conditions
10 through time in this particular period when gas prices are at
11 historic lows.
Q. And you've -- you testified on cross earlier
today that and it's no secret to any of us that appear at the
Commission here that you've been around the Commission and
PURPA things for its entire existence here in Idaho. Is that
correct?
A. Yes, from its -- I was at the Commission, I was
on the Commission Staff, when the original Orders establishing
avoided cost, PURPA, et cetera, were being debated and decided
by the Commissioners.
Q. And would you accept if I told you there's
evidence in the record that Idaho Power has approximately 119
contracts with QF projects?
A. That sounds about right to me.
Q. And, Mr. Reading, based on your experience, do
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you have any idea of how many of those contracts are based on
an SAR-based methodology?
A. I assume all of them.
Q. Pretty close. Would you accept if I said it was
all of them except maybe three?
A. I will yield, but, yeah, the vast majority,
certainly.
Q. So would it be fair to say that what the
Commission was referencing in that Order when it found that
those rates were not just and reasonable nor in the public
interest, it's really talking about rates that were established
under that methodology?
A. Yes. And I would repeat that methodology -- that
it's not the methodology, it's the drivers of the methodology;
and that given current gas prices, it's producing too high a
rate.
Q. So when we talk about what the Commission's
obligation under Federal law is with implementation of PURPA,
it's not necessarily to establish a methodology, is it?
A. My understanding is the Commission -- under
PURPA, the Commission has very wide discretion in determining
avoided cost rates that include the methodology that's used, be
it the proxy or the differential revenue requirement or the
peaker method, that they have the discretion to do that. And
as your witness referenced, a study that was done by NERA shows
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that various Commissions have decided that for their state,
different methodologies are valid.
Q. And so could you say that these are all ways that
various Commissions or that this Commission could choose to set
the avoided cost? Isn't that what their duty really is, to
establish avoided cost?
A. In the public interest, yes.
Q. Okay. And methodology is simply a vehicle that's
utilized to try to get at what the avoided cost should be set
at. Right?
A. Yes.
Q. And you're aware, are you not, that Federal
Regulations define what avoided cost is or should be?
A. To the extent I understand the legalese in those,
yes. It's to determine what the accurate, true, best, what the
Utility -- what the avoided cost is, and that the key phrase I
pull out of that is where customers are indifferent to whether
the Utility builds a resource or whether the power is supplied
by the QF.
Q. Thank you. I think customer indifference, I
would agree, is an important portion.
You testified about something about the 20-year
cost of a Utility-owned resource. Is that found anywhere in
the definition of what avoided cost is?
A. I have not -- I do not recall that in the Federal
I 1037 I
HEDRICK COURT REPORTING READING (X)
P. 0. BOX 578, BOISE, ID 83701 CPC, et al
in Regulations the length of the contract is mentioned anywhere.
2
I would, from my reading of the FERC Regulations and the
3 meaning of PURPA, is that independent power should be

4 encouraged; and in my mind, unless independent power can get
5 sufficiently long contracts, then that is discouraging, not
6 encouraging.

7
Q. Thank you, Dr. Reading. And that was maybe an

8
inartful question. I wasn't intending to ask about the length,
9 more of the components of the avoided cost.

10
And does it make sense to you, does it ring a

11
bell, that avoided costs are defined as incremental costs to

12 the Electric Utility?

13 A. Yes.

14 Q. And the definition, does it ring a bell that that
15 definition specifically references incremental cost that that
16 Utility may incur either by generating electricity itself or by
17 making a purchase but for the addition of that QF energy?

18 A. Yes. And, again, without -- you should never
19 have a witness that used to be a teacher -- without putting my

20
hat on as an economist. Economics profession draws some

21 pretty, I think, unmeaningful differences between avoided cost,

22
incremental cost, marginal cost, et cetera, and there is a wide

23 variety of ways one can define incremental cost.

24
In general, marginal cost is an infinitesimally
.
25 small, over a time period, change in rates. Incremental cost
1038
HEDRICK COURT REPORTING READING (X)
P. 0. BOX 578, BOISE, ID 83701 CPC, et al
is a longer ban of the cost change, and that's what we're
talking about here. An incremental cost, to me, as an
economist, has a time dimension.
Q. So, Dr. Reading, in review of your testimony,
especially your direct testimony, correct me if I'm wrong, but
there's a recurring theme where you refer numerous times to
putting a QF on equal footing with a Utility or a Utility-owned
resource. Is that not a fair characterization?
A. That's a very fair characterization.
Q. So it's fair to say that that's your view of a
proper avoided cost where you would treat a Utility and a QF
the same as far as pricing and recovery of costs?
A. Yes.
Q. And you don't see any difference in those two
entities and the way their costs are or should be recovered?
A. I guess I missed the last one. A Utility's
resource has a different recovery mechanism in that it gets --
when it's approved by the Commission, it gets its capital costs
put in rate base and its variable cost is run, at least in this
jurisdiction, through a production cost adjustment; whereas, a
QF receives a rolled-in capacity and energy payment per kWh
over time. So the recovery mechanisms are different. The
important thing is -- is that the best of our ability, we have
the ending result of those prices the same.
Q. And, Mr. Reading, you offer your testimony in
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2

3
Q. And those are -- would those represent QF

4 developers on each of the three Utilities? Is that --

5 A. Yes.
6
Q. Okay. So can you tell us -- can you tell me what

7 the -- what the authorized rate of return is for any one of

8 those, any one of their developed QF projects?
9 MR. RICHARDSON: Madam Chair, I'll object.

10 That's confidential information, internal QFs, that the Utility

11 is not allowed to inquire into under federal law.

12 COMMISSIONER SMITH: Mr. Walker.

13 MR. WALKER: Can Mr. Reading tell me the answer

14 to that or not?

15 MR. RICHARDSON: Madam Chair, I'll continue my

16 objection that Dr. Reading not be allowed or forced to answer

17 the question.

18 COMMISSIONER SMITH: So let's here the question

19 again.

20 MR. WALKER: I asked if he could tell me the

21 allowed rate of return for any of his clients' QF projects in

22 Idaho.

23 MR. RICHARDSON: Madam Chair.

24 COMMISSIONER SMITH: But they're not regulated,

25 Mr. Walker, so I don't understand the question.
I 1040 I
HEDRICK COURT REPORTING READING (X)
P. 0. BOX 578, BOISE, ID 83701 CPC, et al

1 MR. WALKER: Okay.

2
Q. BY MR. WALKER: Is the rate of return of a
3 Utility something that's known and regulated by this

4 Commission?

5 A. Yes.

6
Q. And I guess the point is the rate of return of a

7 QF is something that's not?

8 A. That is correct, because the PURPA industry and
QFs only meet the obligation that they are afforded the full

10 avoided cost of the Utility.

11 We live in a red state. Competition is a good

12
thing. That's one of the things that I like about the QF
.
13 industry. If a independent developer, under PURPA, can go out

14 and produce electricity cheaper than the Utility can produce it

15
but at the same cost, then that's good for everybody. And if I
16 was a Utility and that was my belief, then I'd want to know

17 what those other guys are doing to be able to produce

18 electricity and make more money than I am.

19
Q. But isn't it true that the QF really doesn't want

20 to be treated just like the Utility for purposes of regulation,

21 does it?

22 A. Other than regulation of avoided cost, no.

23
MR. WALKER: No more questions, Madam Chair.

24 COMMISSIONER SMITH: Thank you, Mr. Walker.

25 Do we have questions from the Commission?
I 1041 I
HEDRICK COURT REPORTING READING (X)
P. 0. BOX 578, BOISE, ID 83701 CPC, et al

1 COMMISSIONER REDFORD: No.

2
COMMISSIONER KJELLANDER: I do not.
3

4 EXAMINATION
5

6 BY COMMISSIONER SMITH:

7 Q. I have one, Dr. Reading. I just have to make

8 sure I heard correctly, because sometimes you think you hear

9 something but you don't.

10 A. Sometimes you think you say something and you
low don't, Madam Chair.

12 Q. That's true too. So in response to a question by
.
13 Ms. Sasser, I thought I heard you say that before RECS

14 existed --

15 A. Yes.

16
Q. the only way that a PURPA project was

17
financially viable was if the Commission set avoided cost rates

18 way too high. Did I hear that correctly?

19 A. If I said that, I will deny at this point that I

20 said it, and I certainly do not mean it.

21 Q. Okay. Well, I -- you know, I wrote it down
22 because I was amazed and --

23 A. No, I do not believe that. I guess go back and

24 look at the record and --
.
25 Q. All right.
I 1042 I
HEDRICK COURT REPORTING READING (Corn)
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1 A. I would correct the transcript if I saw that.

2
Q. Okay. All right. Yeah, I think that -- I think

3 that's my only question.

4
I did note on pages 56 and 57, you talked about
5 the Montana Public Service Commission rejecting a request by
6 NorthWestern Energy to include an economic curtailment

7 provision in future QF contracts?

8 A. Yes.

9 Q. And do you know if NorthWestern owns any

10 generating resources?

11 A. I guess I do not.

12 Q. Would you be surprised if the answer was no, they

13
do not, because in their infinite wisdom --

14 A. -- they sold? When it was Montana Power, they

15 sold it off and went into telecommunications?

16
Q. Yes.

17 MR. UDA: Madam Chair, for the record, I practice

18
in front of the Montana Public Service Commission, and I can

19
tell you NorthWestern does, in fact, own generating resources.
20 And, in fact, they just acquired a 40-megawatt wind project

21 called Spion Kop.

22
COMMISSIONER SMITH: Well we're swear you in,

23 Mr. Uda.

24 MR. UDA: Sorry. I just want to make sure

25 everybody was on the same page.
I 1043 I
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.
1 COMMISSIONER SMITH: Any redirect,
2 Mr. Richardson?
3 MR. RICHARDSON: I do have a couple, Madam Chair.
4 COMMISSIONER SMITH: I warned you about your
lawyer. Remember this.
6
7 REDIRECT EXAMINATION
8
9 BY MR. RICHARDSON:
10
Q. Dr. Reading, you were asked about the $45
11 liquidated security provision?
12 A. Yes.
.
13
Q. And you were asked if it were arbitrary or
14 excessive. But did you address that in your testimony on
15 page 39, suggesting that it should be a mark to market?
16 A. Yeah, that would be a rational way to come to
17 that. And as I remember, that was Mr. Schoenbeck had the same
18 thing in his testimony.
19
Q. So the $45 number may just, by accident, happen
20 to equal what a Utility's damages were, but you can't predict
21 that?
22 A. Right, more or less, yes.
23
Q. And when Ms. Sasser was asking you about your
24 "PURPA killing" remark, did you have a chance to fully answer
.
25 that question, or I thought maybe you had more?
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1 A. What I attempted to say was that -- that the

2 collectivity of what I see as part of this hearing and what is

3 recommended by the Utilities, and especially Staff because they

4 sort of brought them all together, in total would be PURPA

5
killing. One could peel off one of those things maybe and say

6
it is or it isn't, but as a collectivity, it certainly would

7
be. And some of them, I think -- for instance, as I said in my

8
testimony, moving from 20 years to five years by itself would

9 be a PURPA killing.

10
Q. And you were asked by both -- two of the IOUs
11 here about your comment that SAR has been remarkably accurate

12 over time?

13 A. Yes.

14 Q. And that's the key to that statement is "over
15 time." At any one point in time, it may or may not be

16 remarkably accurate?

17 A. Yeah, that is correct. And on one side of the

18 coin, you could look to what the avoided costs were during the

19 run-up in prices when they went $1,500 a megawatt hour or
20 whatever when they were significantly low, to what I thought I

21 was trying to say here in the last couple years anyway, they

22 have certainly been, I think, too high.

23 And as I stated, the way to solve that problem is

24 not to dismantle the QF industry, but work within what is there

.
25 and try to make adjustments.
I 1045 I
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1
Q. And it's not a coincidence that the SAR is a
2 combined cycle combustion turbine and that just happens to be
3 what Idaho Power just brought online this summer?

4 A. Just brought on, yeah, yep.

5 Q. And you were asked about QFs producing capacity.

6 Isn't it reasonable to consider all QFs collectivity as a

7 capacity-producing plant?

8 A. Yes, and as a collectivity reliable high -- as a

9 togetherness, high reliability factors or capacity factor.

10
And another reliable advantage is -- is they are
11 geographically dispersed and so they are putting kilowatt hours

12
into the system over a wider range.

13
Q. And you were asked about the five-year contract
NXIM period, signing a contract five years before operation. And I

15 asked Mr. Kalich this question yesterday about what his
16 business professor would say to signing a five-year contract
17 without knowing what the price would be for three years into

18
it, and since you're a professor, I get to ask you: What do

19 you think of that?

20 A. Well, I think I explained it. If it was me, I

21 would have, I think, a discussion -- which we do -- with

22
Mr. Kalich that you couldn't get financing if you didn't know

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I 1046 I
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Q. And, lastly, you were asked about the IRP process
and whether or not you participated.
A. Yes. And I said -- they asked me if I made a
comment, and I said, yes, I sit in the audience, raise my hand
to make a comment.
Q. Can you tell us your experience, if you recall,
in doing work for the Industrial Customers of Idaho Power in
the IRP process in an attempt to get Idaho Power to consider
using backup generation as a peak load resource?
MR. WALKER: Object: That's leading and beyond
the scope of his cross.
Q. BY MR. RICHARDSON: Can you explain to me some
more detail of your experience in the IRP process,
Dr. Reading?
A. Yeah, the IRP process, as I explained I thought
in my testimony, was that it needs greater vetting. We talked
about my history from the beginning here. The IRPs or planning
documents didn't mean very much 20 years ago. Now, especially,
IRPs are being used to decide a myriad of very important
decisions for a regulated Utility. Avoided cost is just one of
them. Justifying DSM is one of them. Planning what the next
resource should be is one of them.
And what I find sort of I guess curious about it
is -- is the Utilities have come in and said this is -- you
know, everybody can get in the room and everybody can comment,
I 1047
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and so it's a collaborative.
I have two comments on that, I think:
One is that Utility regulation and planning is an
insider's game, and most of the individuals that I see on the
advisory committees, et cetera, are not -- they -- in fact, one
of our clients, Don Sturtevant from Simplot, he's not into the
various models of load forecasting, et cetera, so I think
that -- or how transmission systems are put together. So it's
a fairly complicated process.
The other thing I find curious is the Utilities
come in and say, This is great, this is collaborative, we're
all together, everybody can sign off on it; and then before the
ink dries on the Commissioners' signatures on the accepting
Orders, they want to change the gas price, they want to change
the forecast loads, they want to change everything in between.
And those two -- that doesn't mesh with me. That
is not a consistent view of how the system works.
Q. So you wouldn't set avoided cost rates based on
an IRP methodology, would you?
MR. WALKER: Objection: That is beyond the scope
of cross, and leading and improper.
MR. RICHARDSON: That's all I have, Madam Chair.
COMMISSIONER SMITH: And, fortunately, we have
this wonderful process, so --
MR. RICHARDSON: I have nothing further for
1048
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Dr. Reading.
Madam Chair?
COMMISSIONER SMITH: Thank you, Dr. Reading.
THE WITNESS: Thank you. I made it. Goddamn.
COMMISSIONER SMITH: You made it.
THE WITNESS: Goddamn.
MR. RICHARDSON: May Dr. Reading be excused,
8 COMMISSIONER SMITH: He may.
9 THE WITNESS: Thank you. You won't excuse me.
10 (The witness left the stand.)
11 COMMISSIONER SMITH: All right. We're going to
12 take a break until three o'clock, and when we come back, we
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13 will either start with the Staff witnesses, or we will do
14 Mr. Sorenson or Mr. Hansten if they are here and would like to
15 be taken. So, see you at 3:00.
16 (Recess.)
COMMISSIONER SMITH: So welcome back.
18 Ms. Sasser, I believe we're ready for your
19 witnesses.
20 MS. SASSER: Thank you, Madam Chair. Staff calls
21 Dr. Cathleen McHugh to the stand.
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I 1049 I
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CATHLEEN McHUGH,
produced as a witness at the instance of the Staff, being first
duly sworn, was examined and testified as follows:
DIRECT EXAMINATION
BY MS. SASSER:
Q. Good afternoon.
A. Good afternoon.
Q. Dr. McHugh, would you please state your name and
spell your last name for the record?
A. My name is Cathleen McHugh, Cathleen with a C,
McHugh, M-C, upper case H-U-G-H.
Q. And with whom are you employed and in what
capacity?
A. I'm employed by the Commission Staff, and I'm a
utilities analyst.
Q. Are you the same Dr. McHugh that filed direct
testimony with Exhibits 301, 302, and 303, and rebuttal
testimony with Exhibits 305 and 306 with the Commission?
A. I don't think I filed 303. I think that was
Mr. Sterling's. Did I have three? Let me --
I stand corrected. I did have three. Sorry.
Q. Thank you. Are there any changes or corrections
to your testimony?
I 1050 I
HEDRICK COURT REPORTING McHUGH (Di)
P. 0. BOX 578, BOISE, ID 83701 Staff
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A. I do have corrections to Exhibit 306 in my
rebuttal testimony is I recalculated the avoided cost rates
under the SAR model using the most - the final EIA gas
forecast.
MS. SASSER: If you'll give me one moment,
Mr. Sterling is going to pass out to the Commissioners and the
parties the new numbers that Dr. McHugh is speaking to.
I BY MS. SASSER: I'm sorry, go ahead.
COMMISSIONER SMITH: So is this a replacement for
the existing Exhibit No. 306?
MS. SASSER: It is a replacement for Exhibit 306.
THE WITNESS: And so I've made there two changes:
I've updated the natural gas forecast using the final EIA
forecast which came out in late June, and I also removed an
integration charge that I had applied to solar.
Q. BY MS. SASSER: Thank you. Are there any other
changes or corrections to your testimony?
A. Yes. In my rebuttal testimony on page 3,
starting on page 3, line 23, going through page 4, line 8, that
question can be deleted, as it refers to a section of the old
306 that I did not include for clarity.
Q. Thank you, Dr. McHugh.
COMMISSIONER SMITH: So, let me get this
straight. We are deleting on page 3, line 23, through page 4,
line 8.
I 1051 I
HEDRICK COURT REPORTING McHUGH (Di)
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THE WITNESS: Yes.
MS. SASSER: It refers to a chart that is no
longer on the new exhibit, Madam Chair.
COMMISSIONER SMITH: So do all the parties have a
copy of the replacement Exhibit 306? Yes. Okay, we're good.
Q. BY MS. SASSER: If I were to ask you the
questions laid out in your prefiled direct and rebuttal
testimony, would your answers be the same today?
A. Yes, they would.
MS. SASSER: Madam Chair, I would move that
Dr. McHugh's direct and rebuttal testimony be spread upon the
record as if read, and I would ask that the exhibits be marked
301 through 303, 305 and then 306 on rebuttal.
COMMISSIONER SMITH: So if there's no objection,
we will spread the prefiled direct and rebuttal testimony of
Ms. McHugh upon the record as if it has been read, and we will
admit Exhibits 301 through 303, 305, and 306.
(The following prefiled direct and
rebuttal testimony of Ms. McHugh is spread upon the record.)
I 1052 I
HEDRICK COURT REPORTING McHUGH (Di)
P. 0. BOX 578, BOISE, ID 83701 Staff
Q. Please 1 state your name and business address for
2 the record.
3 A. My name is Cathleen McHugh. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q. By whom are you employed and in what capacity?
6 A. I am employed by the Idaho Public Utilities
7 Commission as a Utilities Analyst.
8 Q. What is your educational and professional
9 background?
10 A. I received a Bachelor of Science degree in
11 Economics and Applied Math from the University of Idaho in
12 1995. I received a Ph.D. in Economics from Duke
13 University in 2005 with primary fields in Public Economics
14 and the Economics of Education and with secondary fields
is in Econometrics (statistics applied to economics), Applied
16 Microeconomics, and the History of Economic Thought.
17 While at Duke University, I taught the
18 undergraduate introductory course on econometrics several
19 times and served as a teaching assistant for the graduate
20 introductory course on econometrics.
21 Between July 2005 and September 2009, I was
22 employed by the Center for Naval Analyses (CNA) as an
23 analyst. My duties there included devising and estimating
24 econometric models for use in military manpower analysis.
25 In this capacity, I co-wrote 17 different publications and
CASE NO. GNR-E-11-03 1053 MCHUGH, C. (Di) 1
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October 2009, I transitioned to a position as a CNA Field
Representative where I provided analytic support directly
to a United States Marine Corps Lieutenant General and his
Command. I remained at this position until joining the
IPIJC in August 2011.
My current duties at the Commission include data
analysis, modeling, resource planning, rate design, cost
of service, and other duties as assigned for electric,
gas, and water utilities.
Q. What is the purpose of your testimony in this
proceeding?
A. The purpose of my testimony is to recommend
updates to the current Surrogate Avoided Resource (SAR)
model.
Q. Will you summarize your recommended changes to
the model?
A. I recommend:
a) Using a forecast of natural gas prices from
the Energy Information Administration's ("EIA")
Annual Energy Outlook report in place of a
forecast from the Northwest Power and
Conservation Council (NWPCC). I recommend this
change because the EIA report is updated more
frequently than the NWPCC report. I further
.
CASE NO. GNR-E-11-03 1054 MCHUGH, C. (Di) 2
5/4/12 STAFF
4
that the EIA forecast be in propose updated the
2 SAR model no later than July l of each year.
3 b) Taking the energy and/or capacity needs of a
4 utility into consideration in calculating
5 avoided costs. An earlier version of the SAR
6 model did this by using the "first deficit year"
7 concept.
8 c) Using resource-specific values for
9 determining capacity payments.
10 d) Allowing for avoided costs to reflect the
11 costs of transmission and loss in periods when
12 the utility is in surplus.
13 Natural gas price forecast •
14 Q. What is the source for the current SAR model's
15 forecast of natural gas prices?
16 A. Pursuant to Order No. 30480, the current SAR
17 model uses the latest available Northwest Power and
18 Conservation Council's (NWPCC) 20-year forecast of natural
19 gas prices. For years beyond those included in this
20 forecast, the model predicts natural gas prices using
21 exponential growth based on the last ten years of the
22 NWPCC forecast.
23 Q. What are the main differences between this
24 forecast and the forecast of natural gas prices from the
25 EIA's Annual Energy Outlook?
CASE NO. GNR-E-11-03 1055 McHUGH, C. (Di) 3
5/4/12 STAFF
i A. With regards to the SAR model, there are two
2 differences between the forecasts of note - the frequency
3 of updates and the geographic focus of the updates.
4 Q. How frequently is the NWPCC forecast updated?
5 What is its geographic focus?
6 A. The NWPCC is directed to review its regional
7 power plan forecast at least every five years per the
8 Pacific Northwest Electric Power Planning and Conservation
9 Act. The 1 8t Power Plan was adopted in 1983. Subsequent
10 plans were adopted in 1986, 1991, 1998, 2005, and, most
ii recently, 2010. Included in the development of this plan
12 is a forecast of natural gas prices.
13 The NWPCC forecast of fuel prices can be updated •
14 independently of the regional plan; in fact, it was
15 revised in 2011 to reflect "a fundamental shift in
16 expectations about future natural gas supplies." However,
17 there is no set timeline for these types of updates.
18 The NWPCC forecast is a regional forecast for
19 the Pacific Northwest (Washington, Oregon, Idaho, and
20 Montana). The forecast includes prices for natural gas
21 delivered to either the west side of the region (west-side
22 delivered) or the east side of the region (east-side
23 delivered). The current SAR model uses the estimate for
24 east-side delivered.
25 Q. How frequently is the EIA forecast updated?
CASE NO. GNR-E-11-03 1056 McHUGH, C. (Di) 4
5/4/12 STAFF
is its 1 What geographic focus?
2 A. The EIA forecast is updated each spring. It
3 provides forecasts of natural gas prices for all Census
4 divisions of the United States. Idaho falls in the
5 Mountain division (Montana, Idaho, Wyoming, Nevada, Utah,
6 Colorado, Arizona, and New Mexico). The specific forecast
7 I recommend using is found in the supplemental tables for
8 regional detail, Table 18: Energy Prices by Sector and
9 Source for the Mountain division/Natural Gas price for
10 Electric Power. This is the delivered fuel price. It
11 should be noted that Avista recommended using the same
12 forecast but for the Pacific division (Washington, Oregon,
13 California, Alaska, and Hawaii). The forecast I propose •
14 be used is included as Exhibit No. 301.
15 I have included both the forecasted real price
16 and the forecasted nominal price. In the SAR model, I use
17 the forecasted nominal price, which eliminates the need to
18 adjust the forecast by any inflation rate.
19 Q. Can you compare the two different forecasts?
20 A. In Exhibit No. 302, I graph four different
21 forecasts of natural gas prices. The first (denoted with
22 circles) shows the most current NWPPC East-Side Delivered
23 forecast. This forecast only extends to 2030 so I also
24 include the estimates that would be used to extend it to
25 2035. These estimates are titled IPUC Estimates based on
CASE NO. GNR-E-11-03 1057 McHUGH, C. (Di) 5
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NWPPC data (the line with diamonds). The next forecast is
the 2011 EIA forecast for the Mountain region (the line
with triangles). Both this forecast and the NWPCC
forecast were released around the same time - the EIA
forecast was released in the spring of 2011 while the
NWPCC forecast was released in summer of 2011. These two
forecasts are very similar especially if one excludes the
first two years. During the entire period, the forecasts
never vary by more than $0.35 and, after the first two
years, they never vary by more than $0.15. The IPUC
estimates are considerably higher than the EIA forecast -
they average almost $0.60 higher.
The final forecast shown is the EIA forecast
released in the spring of 2012 (the line with squares).
Comparing this forecast to the earlier two forecasts
illustrates how much can change in a single year. This
forecast is always lower than the NWPCC forecast - at one
point, it is $0.61 lower. On average, it is $0.32 lower
than the NWPCC forecast. In contrast, the 2011 EIA
forecast was, on average, $0.07 higher than the NWPCC
forecast.
In periods of price fluctuations, relying on a
forecast that is even a year old can dramatically change
the avoided cost computation. In periods of downward
trending prices, the computed cost would be too high if
CASE NO. GNR-E-11-03 1058 McHUGH, C. (Di) 6
5/4/12 STAFF
dated forecast. in one relied on a Conversely, periods of
2 upward trending prices, the computed avoided cost would be
3 too low. Therefore, Staff supports use of the EIA
4 forecast as it will reflect the most current understanding
5 of future natural gas prices.
6 Considering Need in Calculating Avoided Costs
7 Q. How did prior versions of the SAR model take
8 into consideration a utility's need for energy in setting
9 the avoided cost rates?
10 A. A prior version of the SAR model used a "first
11 deficit year" concept. This prior version of the model
12 differed from the current SAR model in that the avoided
13 costs were set equal to "surplus energy rates" for years •
14 in which the utility had surplus energy (years prior to
15 the first deficit year). The surplus energy rate was
16 based on wholesale energy rates and was set by Commission
17 order. Avoided costs for years in which the utility was
18 not in surplus were calculated as they are in the present
19 SAR model.
20 Q. Why was the "first deficit year" concept
21 abandoned?
22 A. At the time this was abandoned, Staff expressed
23 concerns that determining the first deficit year was
24 problematic even though the underlying rationale for it
25 was sound. All together, Staff identified nine areas of
CASE NO. GNR-E-11-03 1059 McHUGH, C. (Di) 7
5/4/12 STAFF
concern regarding the determination of the first deficit
year. These concerns can be grouped in the following
categories:
a)There exists too much discretion on the part
of utilities to influence the results (Reasons
1, 3, 4). As noted by Avista witness Kalich,
this is less true today than in 2002. All the
electric utilities file biennual IRPs which are
developed with input from the public,
regulators, and other interested parties. Thus,
irregular frequency (Reason 1), the
reasonableness of planning assumptions (Reason
3), and the possibility of inaccurate load
forecasts (Reason 4) can all be addressed in the
IRP process.
b)The definition of the first deficit year is
not clear (Reasons 2 and 5). At the time, it
was not clear whether or not the first deficit
year should be based on energy or capacity needs
(Reason 2) or whether it should incorporate firm
market purchases (Reason 5). The proposed
updates take into consideration both energy and
capacity needs so Reason 2 is no longer valid.
Because it is based on the IRP, the proposed
update is consistent with generally accepted IRP
CASE NO. GNR-E-11-03 1060 McHUGH, C. (Di) 8
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3 c) Using the concept of the first deficit year
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5 calculation (Reasons 6 and 8), and,
6 d) Market prices can be extremely volatile
7 (Reason 9). Both of these reasons had more to
8 do with the implementation of the concept rather
9 than the concept itself.
10 Q. Are you instituting the "first deficit year"
11 concept exactly as it had been instituted prior to 2002?
12 A. No. The model I recommend identifies years in
13 which a utility is deficient in energy, in capacity, or •
14 both. This is based on information from each utility's
15 most recent IRP. If a utility is deficient in energy,
16 then the QF would receive an energy payment. If a utility
17 is not deficient in energy, then the QF would receive an
18 energy payment minus costs for transmission and losses.
19 The previous SAR model did not adjust for transmission and
20 losses.
21 In the recommended model, capacity payments are
22 specific to the resource used by the QF. If a utility is
23 deficient in capacity, then the recommended model examines
24 whether the utility is deficient in summer only, in winter
25 only, or in both seasons. If the utility is deficient in
CASE NO. GNR-E-11-03 1061 McHUGH, C. (Di) 9
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i only one season, then the model bases a resource-specific
2 capacity payment on the ability of that resource to
3 contribute during the deficient season's peak. However,
4 if a utility is deficient in both seasons, then the model
5 bases the resource-specific capacity payment on the
6 ability of that resource to contribute during both
7 seasons' peaks. This is the same methodology suggested by
8 Avista.
9 To clarify matters, consider canal drop QF5.
10 Canal drops can contribute 100 percent of their capacity
11 during the summer peak and 0 percent of their capacity
12 during the winter peak. If a utility is only capacity • 13 deficient during the summer, then a canal drop QF receives
14 the full capacity payment. However, if a utility is
15 capacity deficient in only the winter or in both the
16 summer and winter, then the canal drop receives no
17 capacity payment. Allowing capacity payments to differ by
18 resource should encourage development of QFs with
19 characteristics of value to the utilities (such as QF5
20 that provide generation during peak hours).
21 Staff concurs with Avista witness Kalich on the
22 basis for capacity payments. In his direct testimony,
23 page 21, lines 5 through 9, Mr. Kalich states:
24 it is not fair to pay one resource with a
low capacity factor and an equivalently
25 high on-peak contribution the same per-MWh
payment as second base load plant
CASE NO. GNR-E-11-03 1062 McHUGH, C. (Di) 10 5/4/12 STAFF
S 1 operating with a relatively high capacity
factor all year round. Using the method,
2 the low capacity factor resource would
receive much lower total compensation even
3 though the resource provided the same on-
peak capacity benefit to the utility.
4
5 Q. What is the energy payment based on?
6 A. It is based on the cost of fuel and variable
7 operations and maintenance.
8 Q. Avista proposes that energy rates during surplus
9 periods be reduced to account for transmission wheeling
10 costs and losses that the utility would encounter in
11 delivering the QF's energy to a market hub. Do you
12 believe that such reductions in energy rates are
13 justified? •
14 A. Yes, I do. If the energy truly is not needed by
15 the utility to meet its own obligations, then it must sell
16 that surplus energy in the market. Wheeling charges and
17 transmission losses are real costs that must be borne by
18 the utility; therefore, it seems appropriate for those
19 costs to be attributed to the QF that is supplying the
20 surplus energy.
21 I recommend that if the Commission believes it
22 is appropriate to reduce energy rates during utility
23 surplus periods then Idaho Power and PacifiCorp also be
24 directed to propose comparable amounts using an approach
25 similar to that proposed by Avista.
CASE NO. GNR-E-11-03 1063 McHUGH C. (Di) 11 5/4/12 STAFF
i Q. Do you have projected rates based on your
2 proposed changes to the SAR model?
3 A. Yes. These are included as Exhibit No. 303. It
4 should be noted that the results are preliminary and
5 reflect Staff's understanding of the utilities' positions
6 as of the time of filing this testimony. The calculated
7 rates could change during the course of this case due to
8 corrections, revised fuel forecasts, and changes in long-
9 term commitments.
10 For every resource, the rates for Idaho Power
11 and PacifiCorp are higher than the rates for Avista. This
12 largely reflects the fact that Idaho Power and PacifiCorp
13 are deficient in both energy and capacity earlier than •
14 Avista.
15 The rates for canal drop projects are
16 considerably higher for Idaho Power and PacifiCorp
17 compared to other resources primarily because canal drop
18 projects offer capacity during peak summer hours and their
19 capacity payment is spread out over relatively few total
20 hours. This also occurs in the IRP model as discussed by
21 Staff witness Sterling. Canal drop and solar projects
22 have lower rates for Avista compared to the other two
23 utilities because Avista is generally capacity deficient
24 in the winter when neither of these resources produces
25 much energy.
CASE NO. GNR-E-11-03 1064 MCHUGH, C. (Di) 12
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i Wind projects receive the lowest rates among the
2 different types of resources for all three utilities.
3 This reflects wind's low on-peak capacity factor.
4 Q. Have you reviewed the SAR model submitted by
5 Avista? Do you have any comments on it?
6 A. Yes I have reviewed the model and I believe
7 there are several minor errors in the model.
8 First, the Avista model assumes an integration
9 charge of $6.50 per MWh for wind and solar projects.
10 However, pursuant to Order No. 30488, the correct
11 integration charge for Avista and Idaho Power is
12 calculated as a percentage of the levelized avoided cost • 13 rate with the percent applied dependent on the amount of
14 wind/solar on the system. It cannot exceed $6.50 per MWh
15 but it can fall below that amount. Pursuant to Order No.
16 31021, the integration charge for PacifiCorp is $6.50 per
17 MWh.
18 The second minor issue is that the Avista model
19 levelizes the integration charge. The integration charge
20 should be applied annually to the levelized amount. The
21 third minor issue is that the Avista model fails to
22 properly levelize capital costs.
23 Q. Does this conclude your direct testimony in this
24 proceeding?
25 A. Yes, it does.
CASE NO. GNR-E-11-03 1065 McHUGH C. (Di) 13
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i Q. Please state your name and business address for
2 the record.
3 A. My name is Cathleen McHugh. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q. Are you the same Cathleen McHugh who previously
6 submitted testimony in this proceeding?
7 A. Yes lam.
8 Q. What is the purpose of your rebuttal testimony
9 in this proceeding?
10 A. The purpose of my rebuttal testimony is to
11 propose an update to the manner in which capacity payments
12 are calculated in the SAR model. I am effectively
13 providing rebuttal testimony to my earlier direct
14 testimony.
15 Q. What was your previous recommendation in terms
16 of how capacity payments are calculated in the SAR model?
17 A. Previously, I had recommended that when a
18 utility is capacity deficient, resource-specific capacity
19 payments be based on that resource's ability to contribute
20 to the deficient season's peak demand. If both seasons
21 were deficient, then capacity payments would be based on
22 the minimum of the two seasons' capacity contribution.
23 This method is straightforward and
24 computationally simple. Furthermore, it considered the
25 fact that capacity provided by a QF in one season does not
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necessarily translate into capacity avoided by the utility
2 if the utility has to add capacity for the other season,
3 Q. Why are you now proposing changes to this
4 method?
5 A. Since filing direct testimony, Staff has
6 continued to review the SAR model. Quite frankly, during
7 this time Staff devised what it believes is a better
8 method of computing avoided capacity. Staff recognized
9 that if the nameplate capacity of the QF resource was used
10 as an input into the SAR model, then the capacity
11 contribution of the QF could be computed for each year of
12 the contract. Capacity payments could then be based on
13 this capacity contribution.
14 Staff devised a worksheet to be included in the
15 SAR model which demonstrates how the capacity contribution
16 is calculated step-by-step and the resultant factor
17 applied to the capacity payment. The factor represents
18 the share of the capacity payment the QF receives - for
19 instance, a factor of 10 percent indicates the QF would
20 receive 10 percent of the capacity payment. This
21 worksheet is included as Exhibit No. 305 for a 10 MW canal
22 drop hydro project located in Idaho Power's service
23 territory.
24 In 2012-2013, the capacity factor is 0 percent
25 reflecting the fact that Idaho Power is not capacity
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CASE NO. GNR-E-11--03 McHUGH, C. (Reb) 2
6/29/12 STAFF
deficient in those years. In 2014, the factor is 10
2 percent which reflects the fact that only 10 percent of
3 the QF's output can be used to reduce Idaho Power's need
4 for capacity. From 2015 onward, the capacity factor is
5 100 percent reflecting the fact that all the capacity
6 provided by the QF can be used to reduce Idaho Power's
7 need for capacity. As can be seen, this new method is
8 robust to different scenarios regarding the needs of a
9 utility and the ability of a particular QF resource to
10 meet those needs.
11 Q. How does this new method compare to the old
12 method?
13 A. In Exhibit No. 305, I use a star to indicate
14 years in which the capacity factor differs between the two
15 methods and show the capacity factor calculated under the
16 old method. The old method could not differentiate
17 between years in which the utility needed a little
18 capacity (such as 2014) and years in which the utility
19 needed a lot of capacity (years 2015-2031). Furthermore,
20 the old method could not recognize that sometimes capacity
21 provided in only one season did actually translate into
22 capacity avoided by the utility (years 2027-2031).
23 Q. Have you updated Exhibit No. 303 to reflect this
24 new methodology?
25 A. Yes. I have included this as Exhibit No. 306.
1068 CASE NO. GNR-E-11-03 McHUGH, C. (Reb) 3
6/29/12 STAFF
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I have used a star to indicate which rates have changed
from the old method to the new method. Furthermore, I
have indicated the magnitude of those changes. Only the
avoided rates for Idaho Power and Avista change. The
biggest change for both utilities is the rates for canal
drop hydro projects. Under the new method, Idaho Power
rates increase by 7 percent and Avista rates increase by 6
percent.
Q. Are there any other changes you have made to
this exhibit?
A. Yes. I have updated the energy and capacity
needs for PacifiCorp based on new information from the
Company.
Q. Does this conclude your rebuttal testimony in
this proceeding?
A. Yes, it does.
1069 CASE NO. GNR-E-11-03 McHUGH, C. (Reb) 4
6/29/12 STAFF
(The following proceedings were had in
open hearing.)
(Staff Exhibit Nos. 301-303, 305, and 306,
having been premarked for identification, were admitted into
evidence.)
MS. SASSER: And I would present Dr. McHugh for
cross-examination.
COMMISSIONER SMITH: Thank you.
Mr. Solander, do you have any questions?
MR. SOLANDER: I have no questions, Madam
Chairman.
COMMISSIONER SMITH: Mr. Andrea.
MR. ANDREA: No questions.
COMMISSIONER SMITH: Any questions from Idaho
Power?
MR. J. WILLIAMS: No, Madam Chair, not for this
witness.
MR. ARKOOSH: No, Madam Chair.
COMMISSIONER SMITH: Mr. Williams.
MR. R. WILLIAMS: No questions.
COMMISSIONER SMITH: Miller. Mr. Uda?
MR. UDA: No questions.
COMMISSIONER SMITH: Yes. Mr. Richardson.
MR. RICHARDSON: Just a couple, Madam Chair.
1070
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HEDRICK COURT REPORTING McHUGH (Di)
P. 0. BOX 578, BOISE, ID 83701 Staff

1 CROSS-EXAMINATION
2

3 BY MR. RICHARDSON:

4
Q. Good afternoon, Dr. McHugh.

5 A. Good afternoon, Mr. Richardson.
6
Q. On page 8 of your direct testimony, you talk
7 about the IRP methodology and some of the concerns that the

8 Commission expressed when it went and eliminated the first

9
deficit year in the avoided cost calculation?

10 A. Yes.

11
Q. And you endorse using the IRP methodology for

12 setting avoided cost rates?
.
13 A. I'm sorry --

14
Q. Do you endorse --

15 A. -- "endorse" using the IRPs, the IRPs that the

16 Utilities develop?

17
Q. Yes.

18 A. To set the avoided cost rates using the SAR
19 model?

20
Q. Yes.

21 A. Yes.

22
Q. Okay. And you would agree that setting avoided

23 cost rates is a serious business, wouldn't you?

24 A. Very serious.

25
Q. And it sets the stage for transactions involving
1071
HEDRICK COURT REPORTING McHUGH (X)
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millions of dollars, wouldn't you agree?
A. Yes.
Q. And would you agree that avoided cost rates must
be fair, just, and reasonable, as determined by this
Commission?
A. Yes.
Q. And setting retail rates for residential and
commercial customers, that's a serious business too, isn't
it?
A. Yes.
Q. And would you agree that retail rates must be
fair, just, and reasonable as set by this Commission as well?
A. Yes.
Q. And the Utilities, with the Staff's endorsement,
are proposing to use the IRP methodology for setting avoided
cost rates. Correct?
A. May I ask you to clarify? Instead of saying --
because there's the IRP method that Idaho Power has
recommended. Can you say the -- I don't know, instead of
saying the "IRP methodology," can you just say "IRPs"? Would
that --
Q. However you want to clarify it.
A. If that's what you mean by the IRP methodology,
if you mean their IRPs.
Q. Yes.
I 1072 I
HEDRICK COURT REPORTING McHUGH (X)
P. 0. BOX 578, BOISE, ID 83701 Staff
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A. Okay.
Q. And you think using the IRP to set avoided cost
rates will produce fair, just, and reasonable rates?
A. I think there is information in the IRPs that can
be used to set fair -- did you say to set the avoided cost
rates, yes, that are fair.
Q. Using the IRP?
A. Using the information in the IRP5.
Q. And do you think, likewise, that setting retail
rates using an IRP process would result in fair, just, and
reasonable rates?
A. I -- actually, I don't believe I'm here to
testify about setting retail rates.
Q. You're working at the Commission as a rate
analyst, are you not?
A. lam.
Q. So do you know if it would be fair, just, and
reasonable to set retail rates using the IRP methodology?
MS. SASSER: I object to the extent, Madam Chair,
that Mr. Richardson is asking Dr. McHugh about IRP methodology
as I understand his questions, and her testimony is entirely
regarding the SAR methodology. Am I misunderstanding what it
is that he's asking?
COMMISSIONER SMITH: Mr. Richardson, it is very
confusing. And I would note that we're not setting retail
1073 I
HEDRICK COURT REPORTING McHUGH (X)
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rates here, so that seems to be way beyond the scope of this
hearing.
MR. RICHARDSON: I'll move on and pass. Thank
you, Madam Chair.
COMMISSIONER SMITH: Ms. Nelson.
MS. NELSON: No questions, thank you.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: No questions, Madam Chair.
COMMISSIONER SMITH: Did I ask you, Mr. Solander?
MR. SOLANDER: You asked me.
COMMISSIONER SMITH: I've done everyone already.
Do we have questions from the Commissioners?
COMMISSIONER REDFORD: No.
COMMISSIONER SMITH: Nor I.
Any redirect?
MS. SASSER: No redirect, thank you, Madam Chair.
COMMISSIONER SMITH: Thank you for your help.
(The witness left the stand.)
MS. SAS5ER: Unless the other witnesses are
present, are we moving on to Mr. Rick Sterling?
Staff calls Rick Sterling to the stand.
1074 I
HEDRICK COURT REPORTING McHUGH (X)
P. 0. BOX 578, BOISE, ID 83701 Staff

1 RICK STERLING,
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5 DIRECT EXAMINATION
6

7 BY MS. SASSER:

8
Q. Mr. Sterling, would you please state your name
9 and spell your last name for the record?

10 A. Rick Sterling, S-T--E--R-L-I-N-G.

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Q. And with whom are you employed and in what

12 capacity?
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13 A. I am employed by the Idaho Public Utilities
NXIM Commission as the engineering supervisor.

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Q. Are you the same Rick Sterling that filed direct

16 testimony along with Exhibit 304, and rebuttal testimony, with

17 this Commission?

18 A. lam.

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Q. Are there any changes or corrections to your

20 testimony?

21 A. No.

22
Q. If I were to ask you the questions laid out in

23 your prefiled direct and rebuttal testimony, would your answers

24 be the same today?
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25 A. They would.
1075 I
HEDRICK COURT REPORTING STERLING (Di)
P. 0. BOX 578, BOISE, ID 83701 Staff
1 MS. SASSER: Madam Chair, I would move that
2 Mr. Sterling's direct and rebuttal testimony, along with
3 Exhibit 304, be spread upon the record as if read.
4 COMMISSIONER SMITH: If there is no objection, we
5 will spread the prefiled direct and rebuttal testimony of
6 Mr. Sterling across the record as if read, and admit
7 Exhibit 304.
8 (The following prefiled direct and
9 rebuttal testimony of Mr. Sterling is spread upon the record.)
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I 1076 I
HEDRICK COURT REPORTING STERLING (Di)
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Q. Please state your name and business address for
the record.
A. My name is Rick Sterling. My business address
is 472 West Washington Street, Boise, Idaho.
Q. By whom are you employed and in what capacity?
A. I am employed by the Idaho Public Utilities
Commission as the Engineering Supervisor.
Q. What is your educational and professional
background?
A. I received a Bachelor of Science degree in
Civil Engineering from the University of Idaho in 1981
and a Master of Science degree in Civil Engineering from
the University of Idaho in 1983. I worked for the Energy
Division of the Idaho Department of Water Resources from
1983 to 1994. My work focused primarily on development
of renewable energy resources, and also on agricultural
energy conservation. In 1988, I received my Idaho
license as a registered professional Civil Engineer. I
began working at the Idaho Public Utilities Commission in
1994. My duties at the Commission include analysis of a
wide variety of electric, water, and gas utility
applications. I have been the lead Staff person on all
PURPA-related matters that have come before the
Commission since 1994. I am also responsible for
supervising the work of three engineers and four utility
CASE NO. GNR-E-11-03 1077 STERLING, R (Di) 1
5/4/2012 STAFF
analysts.
Q. What is the purpose of your testimony in this
proceeding?
A. The purpose of my testimony is to discuss the
proposals of Idaho Power, PacifiCorp, and Avista made
pursuant to Order Nos. 32352 and 32388. These proposals
relate to the determination of avoided cost rates for
Qualifying Facilities (QFs) under the Public Regulatory
Policies Act of 1978 (PURPA) . More specifically, I will
discuss my position on changes to both the Surrogate
Avoided Resource (SAR) methodology and the Integrated
Resource Plan (IRP) methodology as proposed by each of
the utilities. I will also address other issues raised
in this proceeding, including maximum contract length, QF
contracting procedures and rules, curtailment rules, and
ownership of Renewable Energy Credits (REC5).
Summary of Recommendations
Q. Please summarize your recommendations.
A. My testimony discusses and recommends the
following:
1.That the Commission retain the use of the
SAR methodology for computing avoided cost rates for wind
and solar QFs 100 kW and smaller (nameplate capacity) and
for all other resource types 10 aMW and smaller;
2.That the Commission order the fuel price
CASE NO. GNR-E-11-03
1078
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5/4/2012 STAFF
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i forecast published annually by the U.S. Department of
2 Energy, Energy Information Administration in its Annual
3 Energy Outlook to be used to update published avoided
4 cost rates on July 1 of each year;
5 3. That the Commission adopt other changes to
6 the SAR methodology as discussed by Staff witness Dr.
7 Cathleen McHugh;
8 4. That the utilities implement both the SAR
9 methodology and the IRP methodology in such a way as to
10 not include any value for QF capacity provided in years
when the utility is in a surplus position;
12 5. That avoided cost rates computed under
13 both the SAR and IRP methodologies be reduced during
14 surplus years to account for costs associated with
15 transmission wheeling and losses;
16 6. That a simple cycle combustion turbine
17 (SCCT) be used as the basis for computing capacity value
18 under the IRP methodology for all resource types;
19 7. That the utilities be permitted to update
20 fuel price forecasts, load forecasts, and long-term
21 contract commitments (including QF contracts) between
22 biennial IRP filings for the purposes of computing
23 avoided costs under the IRP methodology,
24 8. That maximum contract length be reduced to
25 five years for contracts containing rates computed under
CASE NO. GNR-E-11-03
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5/4/2012 STAFF
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the IRP methodology;
9.That all three utilities be directed to
submit tariffs similar to PacifiCorp's proposed Schedule
38 outlining QF contracting procedures and rules;
10.That the rates contained in PURPA
contracts not be locked-in more than five years prior to
the scheduled operation date of the QF;
11.That the proposed curtailment tariff
(Schedule 74) proposed by Idaho Power be approved; and
12.That the Commission order that ownership
of Renewable Energy Credits (REC5) be assigned to the
utility.
Q. First, as a preliminary matter, do you believe
that there are changes that need to be made in the way in
which PURPA is being implemented in Idaho?
A. Yes, of course. I think that the utilities
have done a good job in their testimony in this
proceeding as well as in testimony in earlier phases of
this proceeding pointing out some of the problems with
the way PURPA is being implemented and the serious
consequences that have resulted. I am convinced that the
problems they discuss are real and that the consequences
are serious. In my opinion, the single biggest problem
with the current avoided cost methodology is that it
fails to account for whether a utility actually needs new
CASE NO. GNR-E-11-03 1080 STERLING, R (Di) 4
5/4/2012 STAFF
.

1 generation.
2 Q. Do you believe that the problems that have been
3 previously identified exist for all three utilities?
4 A. Yes, although clearly the consequences are most
5 severe for Idaho Power because it has experienced so much
6 more PURPA development in its service territory than the
7 other utilities. Nonetheless, despite the impact being
8 most severe for Idaho Power, I believe that some of the
9 problems that have been identified exist for all of the
10 utilities. Consequently, I propose that if the
11 Commission decides to make changes to avoided cost
12 computation methodologies or to other policies related to
13 Us, that those changes and policies apply to all three
.

14 utilities unless there are clear reasons for utility-
15 specific policies.
16 SAR Methodology
17 Q. Idaho Power has proposed that the SAP.
18 methodology, which is currently used to compute
19 "published" avoided cost rates, be abandoned in favor of
20 using the IRP methodology for "standard" wind, solar,
21 baseload, and canal drop hydro facilities. Do you agree
22 with Idaho Power's proposal to abandon the SAP.
23 methodology for small projects?
24 A. No, I do not. While I agree with Idaho Power
25 that the IRP methodology holds some advantages, even for
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CASE NO. GNR-E-11-03
1081 STERLING, R (Di) 5
5/4/2012 STAFF
i computing standard rates for small projects, I do not
2 believe that the advantages are great enough to warrant
3 abandonment of the SAR methodology entirely. The SAR
4 methodology has been employed in Idaho for computing
5 avoided cost rates since PURPA was first implemented.
6 Although it has been necessary to occasionally modify the
7 method and while it requires some vigilance to ensure
8 input variables and price assumptions are kept updated,
9 the method has generally proved satisfactory. Indeed,
10 the vast majority of PURPA contracts approved to date
11 contain rates computed using the methodology. Project
12 developers have shown a clear preference for the method,
13 admittedly mostly due to its ability to produce favorable
S 14 but believe, because its transparency. rates, also, I of
15 As long as application of the SAR method is restricted to
16 only relatively small projects, I believe it can continue
17 to be successfully used. Furthermore, if fuel prices and
18 other assumptions used in the model are kept updated,
19 then the avoided cost rates calculated using the
20 methodology should be reasonably close to the rates
21 calculated under the IRP methodology. The SAR
22 methodology is intended to model the cost of a CCCT,
23 while CCCT5 are frequently the units setting the market
24 clearing prices under the IRP methodology. The rates
25 under each methodology will never match exactly, but they
CASE NO. GNR-E-11-03 1082 STERLING, R (Di) 6
5/4/2012 STAFF
1 should be reasonably close.
2 100 kW Cap for Wind & Solar Under SAR Methodology
3 Q. Existing rules require that eligibility for
4 avoided cost rates computed using the SAR methodology be
5 limited to facilities no larger than 100 kW (nameplate
6 capacity) for wind and solar projects and 10 aMW for all
7 other resource types. Do you believe that these
8 eligibility limits should be retained?
9 A. Yes, I do. The 100 kW limit for wind and solar
10 facilities was implemented on a temporary basis,
11 beginning on December 14, 2010, in Case No. GNR-E-10-04
12 (See Order No. 32176) primarily to address the
• 13 disaggregation issue related to wind and solar
14 facilities. The ability of these resource types to
15 disaggregate still exists as long as the financial
16 incentive remains. The specific size limit of 100 kW was
17 selected because FERC rules implementing PURPA require
18 that standard rates be established for qualifying
19 facilities with a design capacity of 100 kW or less.
20 (See 18 CFR 292.304(c)). The 10 aMW limit has been in
21 place for many years for other resource types, and I see
22 no compelling reason to change it at this time, provided
23 fuel prices are updated. Both Avista and PacifiCorp have
24 also proposed that the SAR method and its current
25 eligibility limits be retained.
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CASE NO. GNR-E-11-03 STERLING, R (Di) 7
5/4/2012 STAFF
i Q. If the SAR method is retained for small QFs,
2 are there modifications you think should be made to the
3 methodology?
4 A. Yes, there are a few. First, Staff believes
5 that the fuel price forecast used in the model should be
6 updated annually using DOE EIA Annual Energy Outlook. In
7 addition, we believe that the model should be modified to
8 account for utilities' surplus periods. Staff witness
9 Dr. Cathleen McHugh discusses Staff's proposed
10 modifications to the SAR methodology in more detail in
her testimony.
12 IRP Methodology • 13 Q. Idaho Power proposes that the IRP methodology
14 be used to compute avoided cost rates for QFs of all
15 sizes, with "standard" wind, solar, baseload and canal
16 drop facilities used as the basis for rates for small
17 QFs. Do you agree with this proposal?
18 A. No, as I explained previously, I believe that
19 the SAR method should continue to be used for solar and
20 wind facilities up to 100 kW nameplate and for all other
21 project types up to 10 aMW.
22 Avoided Cost of Energy
23 Q. Idaho Power, in the testimony of Karl
24 Bokenkamp, proposes to use the AURORA model to determine
25 the highest displaceable incremental cost being incurred
1084
CASE NO. GNR-E-11-03 STERLING, R (Di) 8
5/4/2012 STAFF
i during each hour of the QF'S proposed contract term. Do
2 you agree with Idaho Power's approach?
3 A. Yes, I do.
4 Q. Idaho Power witness Bokenkamp, at page 13 of
5 his direct testimony, explains how the Company proposes
6 to treat long-term firm purchases. He explains that "if
7 the firm purchase is resold at market price and the QF
8 generation is accepted, then the incremental cost avoided
9 is the net proceeds from the resale of the firm purchase
10 after any transaction-related costs such as transmission
costs, losses, etc." However, to simplify the analysis,
12 Idaho Power proposes to disregard the transaction-related • 13 costs and losses. Do you think this is appropriate?
14 A. No, I do not. Although it would simplify the
15 analysis, transaction-related costs and losses are real
16 and could be significant in many cases; therefore, they
17 should rightfully not be borne by Idaho Power and its
18 ratepayers. In a production request, Staff asked Idaho
19 Power to estimate these costs. Idaho Power responded by
20 stating that transaction costs associated with reselling
21 any of Idaho Power's longer-term firm purchases will
22 depend on the location and timing of the purchases, and
23 on actual market conditions. The Company identifies
24 several alternatives to consider: (1) resell at the point
25 of purchase, (2) deliver the purchase to Idaho Power's
1085
CASE NO. GNR-E-11-03 STERLING, R (Di) 9
5/4/2012 STAFF
system and then resell it at Idaho Power's border,
2 (3) wheel the energy from Idaho Power's border to a more
3 liquid market, or (4) wheel from the point of purchase to
a more liquid market. (See Idaho Power Company's
5 Response to Staff Request No. 18) . In all except the
6 first scenario, Idaho Power admits that it would incur
7 transmission costs and losses. As a reasonable estimate,
8 I would recommend that transmission costs be based on
9 moving surplus energy from Idaho Power's system to the
10 Mid-C market. Under this assumption, transmission costs
11 would be $3 per MWh and losses would be approximately
12 $1.50 per MWh.
13 Q. Under the method used by Idaho Power for
14 computing the avoided cost of energy, an assumption is
15 made that in order to be displaceable, a resource has to
16 be online and capable of staying online and further
17 reducing its output. Therefore, under Idaho Power's
18 method, not all resources are entirely displaceable. Do
19 you agree with the assumptions and methods proposed by
20 Idaho Power?
21 A. Yes, I do. I believe that Idaho Power has
22 properly focused on the incremental costs that the
23 utility would incur as the basis for determining avoided
24 costs. The focus on incremental cost appears entirely
25 consistent with the definition of avoided cost as
1086
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5/4/2012 STAFF
•l contained in 18 C.F.R. 292.101(b) (6). Furthermore, I
the energy component figures provided in the Company's
direct testimony and exhibits, the Company used an
outdated natural gas price forecast. The Company has
used its updated forecast to recompute the energy values
and has incorporated the results of that recomputation in
results provided in Idaho Power's Supplemental Response
to Staff Production Request No. 2. The effect of using a
more updated gas forecast is a small decrease in the
proposed avoided cost rates. Second, Staff discovered
that the displaceable incremental costs for various
thermal units were not being properly escalated in Idaho
Power's analysis to compute the avoided cost of energy.
Idaho Power corrected this error in the results provided
1087
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5/4/2012 STAFF
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believe that the IRP methodology as proposed by Idaho
Power conforms more closely with FERCs definition of
avoided cost than the way in which Idaho Power has
employed the methodology in the past.
Q. Has Staff reviewed in detail the manner in
which Idaho Power proposes to calculate the avoided cost
of energy? If so, did Staff's review identify any errors
in Idaho Power's computations of energy value?
A. Yes, Staff thoroughly reviewed Idaho Power's
methods for calculating the avoided cost of energy. In
our review, we identified a couple of errors. First, in
a. in Supplemental Response to Staff Production Request
2 No. 2. The effect of this correction was a small
3 increase in the avoided cost of energy. The combined
4 effect of both corrections, one positive and the other
5 negative was only a small change to the avoided cost
6 rates.
7 In our review, Staff also identified instances
8 in which it appeared that Idaho Power was operating one
of its own resources during hours when prices in the
10 market were lower. However, further analysis seems to
11 indicate that Idaho Power was likely forced to operate
12 its own higher cost resources in these hours because of • 13 either transmission constraints or because of minimum up
14 times of its thermal resources. Consequently, Staff is
15 satisfied that the analysis performed by Idaho Power is
16 correct.
17 Q. Idaho Power's testimony describes its proposed
18 methodology for computing the avoided cost of energy as
19 being different than the currently approved methodology.
20 Are the two methodologies actually different, and if so,
21 are the differences acceptable?
22 A. Yes, the methodologies are different. However,
23 I believe that the differences are reasonable. One of
24 the primary reasons for the differences is because under
25 the currently approved methodology, there has always been
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a presumption that the dispatch of existing resources
2 would change, or alternatively, that a new resource would
3 be displaced or deferred. In most cases, however, new QF
4 resources are too small to affect dispatch or resource
5 decisions in AURORA. Therefore, unless some modification
6 IS made to the currently-approved methodology, it is not
7 being implemented in the way in which it was intended.
8 Consequently, I believe that the methodology as proposed
9 by Idaho Power is acceptable, and as I stated previously,
10 an improvement over the currently-accepted methodology.
11 Q. One of the key underlying assumptions made by
12 Idaho Power in its modified methodology for computing the
13 avoided cost of energy is that QF generation is not used
14 to make market sales at AURORA-generated market clearing
15 prices. Do you agree with this assumption?
16 A. Yes, I do. I think this assumption is
17 fundamental in order to comply with PURPA as it was
18 intended. Utilities should not be required to make
19 purchases under PURPA in a particular hour if by doing so
20 it is concurrently required to make an equivalent and
21 offsetting sale in order to balance its system.
22 Avoided Cost of Capacity
23 Q. The utilities propose that the value of
24 capacity not be included in avoided cost rates during
25 periods when the utility is surplus. Do you agree with
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this approach?
2 A. Yes, I do. I believe that the failure to
3 account for the utilities' need for new generation is one
of the most serious problems that needs to be addressed
in this case. It is well established that utilities must
6 honor their obligation under PURPA to purchase power
7 offered by QFS. However, utilities are not required, in
8 fact, they are not permitted, to pay more than their
9 avoided cost for capacity and energy provided by a QF.
10 The proper mechanism for accounting for utility need is
n not to relieve utilities of their obligation to purchase,
12 but instead to establish prices for capacity and energy
13 that properly recognize the utilities' need, or lack of
14 need, for capacity and energy. By not paying for
15 capacity during surplus periods, utilities would be
16 paying what amounts to a more accurate reflection of a
17 true avoided cost.
18 Q. Is a utility's need for capacity and energy
19 taken into account under the IRP methodology?
20 A. Yes, I believe that it is under the IRP methods
21 proposed by the utilities in this case. Capacity and
22 energy deficit positions are recognized by the IRP models
23 used by the utilities, and appropriate resources are
24 added at appropriate times in order to satisfy those
25 deficits. If a utility does not have a need for a new
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a. capacity or energy resource, then one is not added until
2 it is needed. Energy values computed by the models are
3 based on economic dispatch of all resources in the
4 utility's portfolio at any given time, subject to the
5 operating constraints and requirements of the various
6 resources.
7 All three of the utilities use methods to
8 determine capacity values under the IRP methodology
9 outside of using their dispatch models (AURORA, GRID, and
10 PRiSM). In the methods used by each utility, none assign
ii capacity value to QFs in years when the utility is in a
12 surplus condition.
13 Q. Didn't the SAR methodology, at one time attempt
14 to account for a utility's surplus period in computing
15 avoided cost rates?
16 A. Yes, it did, from the time PURPA was
17 implemented in Idaho up until 2002, in Case No.
18 GNR-E-02-01, Order No. 29124. At that time the
19 Commission abandoned consideration of utilities' surplus
20 periods in the computation of avoided cost rates for a
21 variety of reasons as discussed in the direct testimony
22 of Avista witness Clint Kalich. While all of the reasons
23 for abandoning consideration of surplus periods made good
24 sense at the time, and while some of the concerns may
25 still be valid today, I believe that the need for
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consideration of surplus periods now outweighs those
concerns. Any difficulty that may exist in considering
surplus periods can be overcome by careful definition of
the term "surplus." I believe that Mr. Kalich has
discussed an acceptable method for determining when a
utility is energy or capacity surplus based on its summer
and winter load-resource balance.
SCCT vs. CCCT as the Basis for Determining Capacity Value
Q. Idaho Power proposes that a simple cycle
combustion turbine (SCCT) be used as the basis for
computing the capacity cost component of avoided cost
rates. Do you agree with this approach?
A. Yes, I do. I made a similar recommendation in
Staff's comments in Case Nos. IPC-E-11-10 (Interconnect
Solar), and IPC-E-11-26 (High Mesa Energy). Idaho Power,
in both of these cases, calculated capacity value using a
CCCT rather than an SCCT. Because of the relatively low
expected capacity factor of these projects, the
intermittent nature of their generation, and the fact
that they cannot be expected to deliver capacity with
complete certainty during the time of the utility's
system peak, I felt that a SCCT would be more appropriate
than a CCCT for computing capacity value.
Q. Do you agree with Idaho Power's proposal to use
an SCCT for computing capacity value for all resource
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1092 CASE NO. GNR-E-11-03 STERLING, R (Di) 16
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1 types regardless of their operating characteristics?
2 A. Yes, I do. SCCTs are generally added to
3 utilities' resource portfolios to satisfy capacity-only
4 needs, and are usually the least cost capacity resource
5 available. Therefore, the cost of an SCCT can reasonably
6 be considered a capacity-only cost. Utilities that add
7 CCCT5 to their portfolio do so because they have a need
8 for both capacity and energy, thus the cost of a CCCT can
be considered both a capacity and energy cost. CCCT5,
10 because they are more efficient, generate energy at a
11 lower variable cost than SCCTs, but the tradeoff is that
12 they are more costly to construct. • 13 Under the methodology as proposed by the
14 utilities, capacity and energy values are being
15 calculated independently. Therefore, I maintain that the
16 proper resource to use as the basis for computing
17 capacity value is the lowest cost resource that could be
18 added to provide capacity equivalent to what would
19 otherwise be provided by the QF. I believe that using a
20 SCCT is probably most appropriate because it represents
21 the lowest cost, nearly capacity-only resource.
22 Q. PacifiCorp proposes that a deferrable CCCT,
23 rather than an SCCT, be used as the basis for computing
24 capacity cost. Do you agree with this approach?
25 A. Although the Company's rationale is sound
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i because CCCT capacity is, in fact, what might presently
2 be deferred by the addition of a QF, I still believe that
3 basing capacity value on the cost of an SCCT is more
4 appropriate for the reasons stated previously.
Peak Hours for Analyzing System Peak
6 Q. In evaluating a potential QFs contribution to
7 meeting the utility's system peak for purposes of
8 computing capacity value, Idaho Power proposes to
9 consider the hours between 3:00 pm and 7:00 pm for all
10 days in July. PacifiCorp proposes to consider the top
11 100 summer peak hours for the years 2007-2010. Do you
12 believe either proposal is acceptable?
. 13 A. I believe there is room for improvement. I am
14 not particularly concerned that each utility define its
15 peak hours in precisely the same way because each
16 utility's peak may occur at different times of the year
17 and because the shape of the peak may differ between
18 utilities. However, I do believe that it is important to
19 consider hours symmetrically around the peak. For
20 example, Idaho Power's approach of considering specific
21 hours in the entire month of July may be too arbitrary.
22 It could be that hours in the third or fourth weeks of
23 June experience higher peak loads than corresponding
24 weeks in late July. Consequently, I would recommend that
25 Idaho Power revise its approach to better identify the
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top peak summer hours independent of whether they occur
in June or July.
Comparison of Results
Q. Have you prepared a comparison of the avoided
cost rates computed by each of the utilities under the
IRP methodology?
A. Yes, I have. Exhibit No. 304 shows the costs
of energy and capacity computed by each of the utilities
using the IRP methodology for four sample project types.
Each sample project type was chosen in order to
illustrate the range of difference in rates for projects
with very different generation characteristics. The base
load project type would be typical of a project with a
very consistent year-round and diurnal generation
pattern, such as a geothermal or biogas facility. The
canal drop project type would be typical of most projects
located on irrigation systems, with steady seasonal
generation, but no generation in the non-irrigation
season. The fixed photovoltaic solar system would be
typical of a facility located in southern Idaho oriented
to maximize on-peak generation. The wind project is
intended to closely represent the same type of facility
that has commonly been installed in southern Idaho in
recent years. In making their calculations, each utility
made exactly the same assumptions of the annual
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i generation amounts and timing for each respective sample
2 resource type. It should be pointed out that the results
3 shown in Exhibit No. 304 are preliminary and reflect
4 Staff's understanding of the utilities' results as of the
5 time of filing of this testimony. The calculated rates
6 could change during the course of this case due to
7 corrections, revised fuel forecasts, and changes in long-
8 term contract commitments.
9 Q. What observations can you make from the results
shown in Exhibit No. 304?
11 A. One observation is that the avoided cost of
12 energy is quite similar for each of the three utilities. • 13 It is also similar for each of the resource types.
14 A second observation is that the differences in
15 rates, both between utilities and between resource types
16 is mostly attributable to differences in the avoided cost
17 of capacity. For example, the avoided cost of capacity
18 is extremely low for the wind project, for all three
19 utilities. This is because of the low probability that
20 wind will be able to provide capacity during the time of
21 any of the utilities' peak load hours.
22 A third observation is that neither a canal
23 drop project nor a fixed pv solar project provides much,
24 if any, valuable capacity for Avista. This is because
25 Avista is a winter peaking utility, and a canal drop
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i facility would not be operating in the winter and a solar
2 facility would provide only minimal capacity during
3 winter evening hours when Avista's peak occurs.
4 A fourth observation is that the rates for
5 canal drop hydro, at least for Idaho Power and
6 PacifiCorp, are higher than the rates for the other
7 resource types. This again is primarily due to the
8 capacity component of the rate being relatively high.
9 The capacity component is high for canal drop hydro for
10 two reasons. First, the capacity is provided during peak
11 summer hours when it is most valuable to the utility.
12 Second, the capacity value is spread over fewer kWhs than
13 for other resource types because a canal drop hydro
14 project would only be operating during the irrigation
15 season.
16 Q. Are the differences in the results for each
17 utility surprising to you?
18 A. No, I expected that the results would be
19 different for each utility because each utility's
20 circumstances are different.
21 Q. Are the differences in the results for each
22 resource type surprising to you?
23 A. No. Each resource type is quite different in
24 its generating characteristics; consequently, it is
25 reasonable to expect that each would provide different
1097 CASE NO. GNR-E-11-03 STERLING, .R (Di) 21
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value, particularly capacity value. Wind resources, for
example, have a very low probability of providing
capacity during the utilities' peak load hours, while
base load types of resources have a high probability.
Therefore, the capacity component of the avoided cost
rate should reflect these differences in value.
IRP Assumption Updates
Q. The IRP methodology relies on numerous
assumptions from the IRP such as fuel price forecasts,
load forecasts, resource costs, load-resource balances,
and composition of preferred portfolios. Do you believe
that the assumptions contained in each utility's last
acknowledged IRP should be locked-in for purposes of
calculating avoided cost rates, or should updates to some
of these assumptions be permitted in the interim between
IRPs?
A. I believe that it is appropriate for some
assumptions to be updated and for others to remain fixed.
In my opinion, the items that should be allowed to be
updated are fuel price forecasts, load forecasts, and new
contract obligations (including new QF contracts).
Fuel price forecasts should be updated
annually. I suggest that the timing of the updates
coincide with whatever schedule is adopted for fuel price
updates made under the SAR methodology. Unlike the
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recommendation for use of the DOE/EIA Annual Energy
Outlook forecast for the SAR methodology, however, I
believe that utilities should be permitted to use the
same forecasts and sources (or combinations of sources)
as they use in their IRPs for use with the IRP
methodology. Although the utilities generally update
their fuel price forecasts more frequently than annually,
I believe that a more frequent update would complicate
contract negotiations if fuel prices are changed too
frequently.
Load forecasts should be updated no more
frequently than annually. New contract commitments
should be updated whenever a new commitment is made,
either for a long-term purchase or a sale. By long-term,
I am referring to any commitment made at least a year in
advance or one extending for a year or more in duration.
Short-term commitments, because they are usually made on
short notice and can frequently change, should not be
considered in the utility's load-resource balance used
for computing avoided cost rates.
New PURPA contracts should be included in the
load resource balance. However, I believe that they
should only be incorporated once a contract has been
signed by the QF and submitted to the utility for
signature. The mere indication of interest or request
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CASE NO. GNR-E-11-03 STERLING, R (Di) 23
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i for a contract is too speculative to justify
2 incorporating a change in the utility's load-resource
3 balance. PURPA contracts that are terminated, expire, or
that have approved modifications of their online dates
5 should also be immediately considered in the load
6 resource balance.
7 Q. Idaho Power proposes that a "queuing" process
8 be established such that upon its receipt of a written
9 request from a QF for contract pricing, the QF is
io designated as "queued" and therefore considered in
11 calculating avoided cost rates. Do you agree with this
12 proposal?
13 A. No, not entirely. As I explained above, I
14 believe that new QFs should not be considered in avoided
15 cost rate calculations until a contract has actually been
16 signed. Technically, Idaho Power's avoided costs do not
17 change until a new QF has actually been added to the
18 resource portfolio. A QF that has not signed a contract
19 cannot yet be considered part of the resource portfolio.
20 However, once a contract is signed for one QF, the
21 avoided cost rate for all successive QFs, even if they
22 are still in negotiation of a contract, should also
23 change accordingly.
24 Q. What assumptions and variables do you recommend
25 remain fixed between IRP filings?
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1 A. I recommend that all variables and assumptions
2 other than the ones I just mentioned remain fixed. This
3 would include, for example, the timing and composition of
the portfolio of new resources to be added, new resource
5 costs, resource characteristics, operational
6 characteristics, transmission assumptions, discount rates
7 and other financial assumptions.
8 Contract Length
9 Q. Idaho Power is proposing that maximum contract
10 length be reduced from 20 years to 5 years. Do you agree
11 with the Company's proposal?
12 A. Yes, I do.
El
13 Q. Has the Commission ever before limited
14 contracts to five years or less?
15 A. Yes, it has. The Commission's policy with
16 respect to standard contract length has evolved over the
17 years. From 1980 when PURPA was first implemented in
18 Idaho, through 1987, utilities were obligated to offer
19 QF5 up to 35-year contracts. The reason for the 35-year
20 maximum contract length was that 35 years was the
21 amortization period allowed for similar utility-owned
22 facilities. A contract length that matched the project's
23 amortization schedule served to make financing easier,
24 and in effect, helped encourage QF development.
25 In 1987 (See Case No. U-1500-170, Order No.
CASE NO. GNR-E-11-03 1101 STERLING, R (Di) 25
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i 21630) the Commission shortened the standard contract
2 length to 20 years reasoning that risk and uncertainty
3 inherent in long-range forecasting increases dramatically
4 with time and that a shorter contract term would reduce
5 that risk. The Commission ruled that contracts longer
6 than 20 years would be available to QFs only upon a
7 persuasive showing of need.
8 Nine years later, in 1996, the Commission again
9 reexamined the issue of contract length. In Order No.
10 26576 in Case No. IPC-E-95-9, the Commission further
ii shortened the required contract length from 20 years to
12 five years for projects 1 MW and larger. In 1997, the
. 13 Commission extended the five-year contract length
14 limitation established for large QFs to smaller than 1 MW
15 QFs as well. (See Case No. IPC-E-97-9, Order No. 27111)
16 shortly after approving Idaho Power's Application to
17 limit all QF contracts to five years, both Avista and
18 PacifiCorp petitioned for and received approval to
19 limit all QF contracts to five years. (See Case Nos.
20 WWP-E-97-8, Order No. 27212; UPL-E-97-4, Order No.
21 27213)
22 In 2002, the Commission increased maximum
23 contract length from 5 years back to 20 years. The
24 Commission explained that when it earlier had reduced
25 maximum contract length to five years, there was an
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expectation of widespread deregulation, more competitive
markets, and greater reliance on short-term market
purchases. However, by 2002, the Commission recognized
that each of Idaho's regulated electric utilities were
constructing or had recently constructed long-term new
generation resources. In restoring 20 years as the
maximum contract length, the Commission reasoned that a
longer contract better coincides with the amortization
period or planned resource life of the renewable or
cogeneration resources being offered, better reflects the
amortization period of generation projects constructed by
the utilities themselves and will coincidently provide a
revenue stream that will facilitate the financing of QF
projects. (See Order No. 29029).
Q. During the approximately five and a half year
period when contract length was limited to five years
(September 1996 through May 2002), how many PURPA
contracts were signed?
A. There was only one PURPA contract signed in
Idaho during this time frame. However, at the time, the
eligibility cap for published rates was also limited to
facilities one megawatt or smaller. In addition,
published rates were also quite low, primarily due to low
natural gas prices. Furthermore, most PURPA hydro and
cogeneration projects had already been developed, while
CASE NO. GNR-E-11-03 1103 STERLING, R (Di) 27
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wind, solar and biogas technologies had yet to fully
2 develop. The combination of all of these factors, not
3 shortened contract length alone, caused very few PURPA
4 projects to be developed in Idaho during this time
5 period.
6 Q. But won't a five-year limit on maximum contract
7 length, if approved, severely limit the ability of
8 projects to obtain financing, thus making extensive
9 project development unlikely?
10 A. I agree that development would likely slow
11 considerably, at least under PURPA. However, large
12 facilities could still be developed with long-term
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13 contracts in response to utility requests for proposal,'
14 just as they are in most of the rest of the country.
15 Alternatively, projects could also sign PURPA contracts
16 and renew them every five years as long as PURPA remains
17 in effect. If the significantly lower rates proposed by
18 various parties in this proceeding are ultimately adopted
19 by the Commission, any project signing a contract at low
20 rates would probably not want to be locked into those
21 rates for 20 years, and would welcome the opportunity to
22 sign new contracts at five-year intervals.
23 Q. Do you believe that the Commission has a
24 responsibility to ensure contract lengths are long enough
25 to enable QFs to obtain financing?
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1 A. No, not necessarily. Long-term contracts have
2 been used by the Commission in the past to boost
3 development of PURPA projects. However, circumstances
4 have changed. It would be contrary to the public
5 interest to encourage PURPA development at a time when it
6 is not needed to serve customers and at a time when poor
7 economic conditions strain customers' ability to pay. I
8 believe it would be good public policy for the Commission
9 to use effective tools, such as limiting maximum contract
10 length, to control the pace of PURPA development.
11 Q. Are there any requirements under PURPA
12 regarding contract length?
. 13 A. No, FERC'S regulations implementing PURPA are
14 silent on contract length.
15 Q. Are there other reasons why you believe that
16 maximum contract length should be shortened to five
17 years?
18 A. Yes, there are. When the SAP. was changed from
19 a coal-fired resource to a gas-fired resource in 1995,
20 fuel became a much larger portion of the avoided cost
21 rate. By comparison, fuel is a far more substantial
22 portion of costs for a gas-fired resource than for a
23 coal-fired resource. In fact, for the gas-fired CCCT now
24 used as the SAR, fuel represents approximately two thirds
25 of the project costs. Currently, the fuel component of
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C
1 costs must be estimated based on 20-year forecasts. As
2 history has demonstrated, it can be extremely difficult
3 to accurately forecast gas prices just a few years into
4 the future, let alone 20 years into the future.
5 Similarly, under the IRP methodology, much of the cost
6 upon which PURPA rates are based is driven by fuel
7 prices. Gas-fired generation is on the margin much of
8 the hours of the year; consequently, electric market
9 prices are frequently closely tied to natural gas prices.
10 A five-year contract allows contract rates to be adjusted
ii regularly to more accurately reflect current fuel prices.
12 The shorter the term of the contract, the more
13 frequently prices can be adjusted to ensure they
14 accurately represent the true value of the power. A
15 shorter term contract helps to minimize risk for both the
16 buyer and the seller.
17 Q. Some people have argued over the years that
18 PURPA projects, because the prices are established at the
19 start of the contract term and are fixed for the 20 years
20 of the contract, present little or no fuel price risk
21 compared to gas-fired generation acquired by utilities.
22 Do you agree?
23 A. No, I do not. Although there may be no price
24 uncertainty associated with long-term PURPA contracts,
25 that is not the same as having no price risk. Prices
1106 CASE NO. GNR-E-11-03 STERLING, R (Di) 30
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i established at the start of a long-term contract could
2 prove to be too high or too low compared to other
3 alternatives or to market prices in effect throughout the
4 term of the contract. A long-term contract locks in
5 those prices, regardless of what happens with market
6 prices. Because 100 percent of PURPA costs are passed on
7 to customers through PCA5, ratepayers are fully exposed
8 to the risk that PURPA rates may prove to be too high.
9 Fuel costs associated with utility-owned
10 resources are also passed on to customers, partly through
base rates and partly through PCA5. However, fuel costs
12 are tracked annually and rates are adjusted accordingly. • 13 Consequently, while customers are exposed to fuel price
14 risk for both PURPA and utility-owned resources, the
15 annual adjustment of rates for utility-owned resources
16 exposes customers to less risk for utility-owned
17 resources than for PURPA resources. Moreover, recovery
18 of costs for utility-owned resources is not guaranteed.
19 However, as previously stated, once a PURPA contract is
20 approved by the Commission, customers are obligated to
21 pay 100 percent of the costs.
22 Q. Is it your position that contracts be limited
23 to five years for all QFs, or only those eligible for
24 rates determined under the IRP methodology?
25 A. It is my position that contracts be limited to
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1 five years only for those QFs eligible for rates
2 determined under the IRP methodology. Twenty-year
3 contracts should continue to be available to QFs under
4 the SAR methodology.
5 QF Contracting Procedure & Rules
6 Q. PacifiCorp proposes in this case that a tariff
7 (Schedule 38) be adopted specifying contracting
s procedures and rules for QF contracts. Do you support
9 this proposal?
10 A. Yes, I do. The Commission has never maintained
11 rules or required specific procedures in the past, but I
12 believe that they could be helpful now for both the
• 13 utilities and project developers. A fair, consistent set
14 of rules and procedures would inform both parties of
15 their responsibilities, informational requirements, and
16 timelines. It could also help to alleviate complaints.
17 Q. Would you recommend that the tariff proposed by
18 PacifiCorp be adopted by the Commission for use by all
19 three utilities?
20 A. No. I believe that each utility needs to
21 develop its own tariff tailored to meet its own needs,
22 subject to approval of the Commission. I would recommend
23 that each of the utilities be directed to prepare similar
24 tariffs to PacifiCorp's Schedule 38, and that a separate
25 docket be opened for review and comment on the specific
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details that would be contained in each proposed tariff.
Although Idaho Power has stated that it supports a
similar tariff, it has not submitted a draft proposed
tariff.
Advance Contract Commitment, Price Lock-in
Q. Avista proposes that utilities should not be
required to execute PURPA contracts more than five years
ahead of expected deliveries. Do you agree with this
proposal?
A. Although I agree with the objective of the
proposal, I think it may be difficult to implement in
order to ensure that it does not conflict with the
utility's obligation to offer to purchase under PURPA.
Avista has made a second proposal, however,
that could successfully achieve a similar objective.
Avista's second proposal is that rates contained in a
PURPA contract not be locked in more than two years ahead
of commercial operation. Project developers typically
need to obtain a power sales agreement and the certain
avoided rates contained within it before they can obtain
financing to proceed with their project. Completing the
project can then take several years, depending on the
type and size of the facility. A developer might
experience delays for various reasons while he diligently
pursues his project. But delays can also occur due to
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CASE NO. GNR-E-11-03
1109 STERLING, R (Di) 33
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deliberate actions or inactions of the developer. Many
things can change during the time a developer is working
on his project, including power prices. Although I
believe that a developer needs price certainty and the
assurance of a utility obligation to purchase during the
reasonable course of developing a project, I do not
believe that the same price certainty and assurance
should be preserved indefinitely. Few projects achieve
commercial operation within two years of contract
execution, but most achieve it within five years. I
believe five years after contract approval is a
reasonable period of time to preserve rates contained in
an initial contract. If a project cannot be completed
and achieve commercial operation within five years, then
the utility, while it may still have a continuing
obligation to purchase under PURPA, should be permitted
to recompute rates in the contract based on whatever
rules, assumptions and methods are in place at the time
of the recomputation. Avoided cost rates could either
increase or decrease in the interim between contract
execution and commercial operation; consequently, I
believe it would be fair to permit the utility to
recompute new rates after five years if they would be
lower than the original rates, or to maintain the
original rates if the QF's failure to achieve commercial
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operation as scheduled is not the fault of the utility.
Q. Avista proposes that utilities be permitted to
terminate contracts 180 days beyond the committed online
date in the contract if projects fail to come online, and
that a security deposit for liquidated damages be due at
the time a legally enforceable obligation is incurred -
i.e., Avista states, when 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 agree with these proposals?
A. I think utilities can already insert conditions
in contracts that allow them to terminate contracts 180
days beyond the committed online date when projects fail
to come online; therefore, I do not believe that any
further authorization from the Commission is necessary.
Security deposits for delay liquidated damages
have become standard in all recent PURPA contracts. A
requirement that a security deposit for liquidated
damages be due when a QF developer executes and returns
the tendered contract would be a change from current
practice. The Commission has never specified in any of
its orders the timing of when a security deposit is due.
However, I believe Avista's proposal has merit. It seems
fair that if a QF can unilaterally impose a legally
enforceable obligation on a utility, the QF should
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CASE NO. GNR-E-11-03 1111 STERLING, R (Di) 35
5/4/2012 STAFF
i contemporaneously incur a corresponding obligation to
2 perform backed by a posting of required security for
3 liquidated damages.
4 Curtailment (Idaho Power Schedule 74)
5 Q. Idaho Power proposes that the Commission
• 6 approve a tariff (Schedule 74) that governs operational
7 dispatch of QFs, including curtailment under certain
8 circumstances. Do you support the proposed tariff?
9 A. Yes, I do. The proposed tariff would establish
10 rules under which Idaho Power could curtail certain QFs
if, due to operational circumstances, purchases from the
12 QF would otherwise require the Company to dispatch higher
13 cost, less efficient resources to serve system load or to
base load 14 make resources unavailable for serving the next
15 anticipated load.
16 Q. Doesn't Idaho Power already have authority to
17 curtail QF5 under certain circumstances?
18 A. Yes, they do under Schedule 72 and under the
19 terms of all PURPA power sales agreements, but only in
20 response to system integrity issues. Schedule 72
21 generally addresses interconnection of non-utility
22 generation, but specifically includes provisions that
23 allow disconnection under circumstances in which
24 "...the Seller's operation or maintenance of the
25 Generation Facility or Interconnection Facilities is
.
CASE NO. GNR-E-11-03 1112 STERLING, R (Di) 36
5/4/2012 STAFF
unsafe or may otherwise adversely affect the Company's
equipment, personnel, or service to its customers."
Unlike Schedule 72 that gives the Company authority to
curtail, the proposed Schedule 74 addresses policies and
procedures for operational dispatch of Idaho Power's own
resources in addition to QF resources.
Q. If Idaho Power already has authority to curtail
Us under certain circumstances, why is an additional
tariff necessary?
A. As I stated, the existing Schedule 72 gives the
utility the authority to curtail under certain
circumstances, but the proposed Schedule 74 details
specific policies and procedures to be followed under
curtailment. I am aware that Idaho Power has curtailed
wind projects on its system several times this year
following the same procedures outlined in the proposed
tariff. If Idaho Power intends to follow these
procedures, it would be desirable that they be contained
in a Commission-approved tariff to help ensure clarity,
consistency, and fairness.
Schedule 74 would also address Idaho Power's
ability to curtail for reasons related to system
efficiency and economics, reasons not allowed under
Schedule 72.
Q. Idaho Power proposes that Schedule 74 apply to
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CASE NO. GNR-E-11-03 1113 STERLING, R (Di) 37
5/4/2012 STAFF
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all QF facilities, both existing and new, that have
Generator Output Limiting Controls (GOLC5) installed. Do
you believe that, if approved, the Company would have the
authority to apply the proposed tariff to existing
facilities whose contracts were in place prior to the new
tariff being adopted?
A. Yes, I do. As explained by Idaho Power witness
Tessia Park, FERC rules at 18 CFR 292.304(f) includes a
provision that relieves utilities from an obligation to
purchase during any period which, due to operational
circumstances, purchases from QFs will result in costs
greater than those which the utility would incur if it
did not make such purchases, but instead generated an
equivalent amount of energy itself. Because this is a
part of FERC rules, I think Idaho Power has always had
that authority whether or not it is expressly spelled out
in a contract or a tariff.
Q. Has clarification of 18 CFR 292.304(f) ever
been made by FERC?
A. Yes. In Order No. 69, FERC clarified that 18
CFR 292.304(f) was intended to deal with a certain
condition which can occur during light loading periods—
conditions that I believe are properly explained by Idaho
Power witness Park.
.
CASE NO. GNR-E-11-03 1114 STERLING, R (Di) 38
5/4/2012 STAFF
i Renewable Energy Credits
2 Q. PacifiCorp in this case took a position that
3 ownership of Renewable Energy Credits (RECs) associated
4 with QFs should be assigned to the utilities. Idaho
5 Power pointed out that REC ownership is being debated in
6 Case No. IPC-E-11-15 and that, at the time Idaho Power
7 filed its testimony, the Idaho Legislature was
8 considering legislation addressing REC ownership. Avista
9 was silent on the issue. Do you believe that this issue
10 should be addressed in this proceeding?
11 A. Yes, I do. Depending upon one's point of view,
12 RECs are either directly or indirectly associated with
13 the capacity and energy produced and sold to utilities by
all QFs. not 14 nearly Despite the fact that Idaho has
15 adopted any standards requiring that utilities possess
16 RECs (i.e., renewable portfolio standards), they
17 nevertheless are generated by QFs and have value to
18 whichever entity is deemed to own them. In addition, the
19 disposition of RECs between the utility and the QF owner
20 is typically addressed in most new power sales
21 agreements, except for those in which the parties are
22 unable to agree on REC ownership in which case the
23 agreements are silent regarding ownership. While some
24 recent contracts have been silent, others have granted
25 full REC ownership to the QF owner, others have split REC
CASE NO. GNR-E-11-03 1115 STERLING, R (Di) 39
5/4/2012 STAFF
1 ownership 50/50 between the QF owner and the utility from
2 the beginning of the contract throughout its entire term,
3 while still others have split REC ownership with the QF
4 possessing them for the first half of the contract term
5 and the utility possessing them for the last half.
6 Although negotiation of REC ownership has proven to be
7 possible in some instances, parties have reached an
8 impasse in other cases. Nonetheless, in every case, REC
9 ownership has been an extremely contentious issue. I
10 believe that rules need to be established in order to
ensure consistency and to avoid disputes.
12 Q. PacifiCorp witness Clements proposes that
13 Environmental Attributes (REC5, green tags) generated by
14 a QF go to the utility whenever the QF sells energy to
the utility and receives compensation for that energy at
16 approved avoided cost rates. What is your position on
17 this issue?
18 A. I agree with Mr. Clements that REC ownership
should be decided in favor of the utilities, but my
20 reasoning is a bit different.
21 Q. Can you summarize some of the common arguments
22 made concerning REC ownership?
23 A. Yes. Arguments justifying REC ownership have
24 been made throughout the country from the time when REC5
25 were first defined. The arguments generally fall into
.
CASE NO. GNR-E-11-03 1116 STERLING, R (Di) 40
5/4/2012 STAFF
one or more of several categories. First, some arguments
2 focus on the responsibility and timing of creation of the
3 REC5. Some argue that the QF developer should own the
4 RECs because the developer made the investment and took
5 the risk in building the renewable facility, that the
6 RECs are created the instant the kWhs are generated, and
7 that absent the facility, no RECs would exist. Others
8 argue that RECs are not created until the kwhs are sold
9 to the utility, and that RECs owe their very existence to
10 the fact that the energy was purchased by the utility,
11 thus the utility should own the RECs.
12 A second class of arguments, similar to Mr.
13 Clements', focuses on belief that REC ownership by the
is 14 utility a necessary condition of purchases made from
15 QFs because of the presumption that renewable attributes
16 are an implied requirement for QFs under PURPA, and that
17 stripping these attributes destroys the very essence of
18 the product PURPA obligates utilities to purchase. This
19 argument suggests that the purchaser of the energy should
20 be entitled to all of the attributes of that energy.
21 A third class of arguments focuses on costs.
22 The basic argument is that the avoided cost rate should
23 take into account REC ownership. If the purchase by the
24 utility of a kWh includes a bundled REC, then the price
25 paid by the utility should be higher than if only the kWh
.

CASE NO. GNR-E--11--03 1117 STERLING, R (Di) 41
5/4/2012 STAFF
alone is delivered.
2 Q. Why do you believe that REC ownership should be
3 decided in favor of the utilities?
4 A. All of the arguments summarized above have
5 merit and may be persuasive in justifying REC ownership
6 be either the utility or the QF. In the end, however, I
7 believe that the public interest is paramount in any
8 decision on REC ownership in Idaho. In my opinion, the
9 public interest is best served if REC ownership is
10 granted to the utilities.
11 For example, if Idaho was in a position where
12 additional incentive was needed in order to stimulate
13 further development of .renewables or achieve an RPS
14 standard, then it might be reasonable to assign ownership
15 of RECs to QF project owners so that they would have an
16 additional revenue stream that could enhance project
17 economics. However, as recent history demonstrates,
18 Idaho is not in a situation where renewables development
19 is stalled or needs to be accelerated.
20 If the real purpose of an RPS standard is to
21 stimulate renewables development, then it seems that
22 objective is achieved once a renewable project is built.
23 If a utility did not receive the REC5 from that project
24 and instead was forced to purchase or obtain REC5
25 elsewhere, then it seems that twice the incentive would
. CASE NO. GNR-E-11-03 1118 STERLING, R (Di) 42
5/4/2012 STAFF
be created for developing renewables projects—once for QF
2 developers who sell RECs to out-of-state entities and
3 once for the utility who must purchase RECs to satisfy
4 its own requirements. Although such a result may not be
5 intended, if an RPS requirement did exist and had to be
6 met, utilities could be in a position of having to
7 acquire RECs just to meet the standard when it might
B otherwise have been able to meet the standard using RECs
9 associated with QF8 from which it must purchase power
under PURPA.
11 Q. Has FERC provided any guidance regarding REC
12 ownership?
A. Yes, some. FERC has made clear that REC
14 ownership is a matter for states to decide. The key case
is addressing REC ownership is the following: American Ref-
16 Fuel Company, 105 FERC ¶ 61,004 (2003)
17 In American Ref-Fuel, several QFs had
18 petitioned FERC for an order declaring that avoided cost
19 contracts entered into pursuant to PURPA, absent express
20 provisions to the contrary, do not inherently convey to
21 the purchasing utility any RECS. Id. at 61,005. In
22 response, FERC addressed the relationship between PURPA
23 contracts for the sale of QF capacity and energy and the
24 ownership of REC5. FERC specifically declared the
25 following:
CASE NO. GNR-E-11-03 STERLING, R (Di) 43
5/4/2012 1119 STAFF
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23... .RECs are relatively recent creations of
the States. Seven States have adopted Renewable
Portfolio Standards that use unbundled REC5.
What is relevant here is that the RECs are
created by the States. They exist outside the
confines of PURPA. PURPA thus does not address
the ownership of REC5. And the contracts for
sales of QF capacity and energy, entered into
pursuant to PURPA, likewise do not control the
ownership of the RECs (absent an express
provision in the contract). States, in creating
RECs, have the power to determine who owns the
REC in the initial instance, and how they may
be sold or traded; it is not an issue
controlled by PURPA.
24. We thus grant Petitioners' petition for a
declaratory order, to the extent that they ask
the Commission to declare that contracts for
the sale of QF capacity and energy entered into
pursuant to PURPA do not convey REC5 to the
purchasing utility (absent an express provision
in a contract to the contrary). While a state
may decide that a sale of power at wholesale
automatically transfers ownership of the state-
created RECs, that requirement must find its
authority in state law, not PURPA.
American Ref-Fuel, 105 FERC at 61,007.
Thus, FERC concluded that RECs are created by
the State and controlled by state law, not PURPA, and
that they may be decoupled from the renewable energy.
More specifically, FERC ruled that states have the power
to determine who owns REC5.
Q. FERC's order in Am Ref-fuel says that contracts
for the sale of QF capacity and energy entered into
pursuant to PURPA do not convey RECs to the purchasing
utility. Wouldn't it therefore be reasonable to conclude
.
CASE NO. GNR-E-11-03 1120 STERLING, R (Di) 44
5/4/2012 STAFF
that RECs are owned by the QF, absent an express
2 provision in the contract to the contrary?
3 A. No, I contend that such an interpretation can
4 only be reached by taking language from FERC's order out
5 of context. The Petitioners in Am Ref-fuel specifically
6 asked for a declaration that "contracts for the sale of
7 QF capacity and energy entered into pursuant to PURPA do
8 not convey RECs to the purchasing utility." FERC's
9 answer granted the petition and addressed the precise
10 question it was asked to decide. It went no further,
11 except to say that REC ownership is a matter for states
12 to decide. FERC was not asked to rule on the converse
13 question that contracts for the sale of QF capacity and
into 14 energy entered pursuant to PURPA do not convey RECs
15 to the QF. I believe a reasonable interpretation of
16 FERC's order is that contracts under PURPA, absent
17 express provisions, do not convey REC5 to either party,
18 nor do they dictate REC ownership. Any interpretation
19 that implies that FERC stated that QFs own RECS seems to
20 me to be a case of starting with a conclusion and working
21 backwards, and requires reading far more into FERC's
22 decision than is actually there. Similarly, any
23 suggestion that FERC determined that RECs are owned by
24 the QFs would, in my opinion, be inconsistent with FERC's
25 determination that REC ownership is a matter for states
CASE NO. GNR-E-11-03 1121 STERLING, R (Di) 45 5/4/2012 STAFF
to decide.
2 Q. Aside from the need for the Commission, the
3 Legislature, or the courts to determine REC ownership,
are there pricing issues associated with RECs that need
5 to be considered in setting avoided cost rates?
6 A. Yes, there are. For example, under the IRP
7 methodology, a utility's 20-year portfolio of new
8 resources is modeled in computing avoided cost rates.
9 Each utility's 20-year resource portfolio contains some
10 renewable plants because they either represent the lowest
cost resources or because they help satisfy expected RPS
12 requirements or both. The utility would possess the RECs
13 associated with resources contained in its preferred
14 portfolio, and presumably any price premium associated
with those RECS would be included in the cost of the
16 projects. Consequently, the cost of RECs would, already
17 be accounted for in computing avoided cost rates using
18 the IRP methodology. Therefore, a utility paying the
19 computed avoided cost to a QF under the IRP methodology
20 should be entitled to ownership of the RECs.
21 Under the SAR methodology, however, because the
22 SAR is a gas-fired resource that does not produce RECs
23 and the QF is presumably a renewable resource that does
24 produce RECs, some adjustment to the avoided cost rates
25 may be necessary. If the utility is deemed to own the
is
CASE NO. GNR-E-11-03 1122 STERLING, R (Di) 46
5/4/2012 STAFF
RECs associated with the QF, then an adjustment to the
2 avoided cost rates is necessary because capacity and
3 energy from the QF simply offsets capacity and energy
4 otherwise provided by the SAR. The RECs would be a
5 unique attribute of the power provided by the QF. The
6 utility would then be expected to pay some amount in
7 addition to the published avoided cost rates if it wished
8 to own the RECs.
9 Q. Does this conclude your direct testimony in
10 this proceeding?
11 A. Yes, it does.
12
13
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CASE NO. GNR-E-11-03 1123 STERLING, R (Di) 47
5/4/2012 STAFF
1 Q. Please state your name and business address for
2 the record.
3 A. My name is Rick Sterling. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q. By whom are you employed and in what capacity?
6 A. I am employed by the Idaho Public Utilities
7 Commission as the Engineering Supervisor.
8 Q. Are you the same Rick Sterling who previously
9 submitted testimony in this proceeding?
10 A. Yes, I am.
11 Q. What is the purpose of your rebuttal testimony
12 in this proceeding?
13 A. The purpose of my rebuttal testimony is to
14 address the direct testimony of Richard Guy of Idaho Wind
15 Partners I, LLC and the direct testimony of Don
16 Schoenbeck, witness for the Twin Falls and North Side
17 Canal Companies and the Renewable Energy Coalition as
18 their testimonies relate to 18 C.F.R. 292.304(f)
19 ("Section 304(f)"), the FERC rule implementing PURPA that
20 deals with curtailment under certain circumstances.
21 Q. Do you agree with Mr. Guy's and Mr.
22 Schoenbeck's interpretations of Section 304(f)?
23 A. No, I do not.
24 Q. Please explain why you believe their
25 interpretations of Section 304(f) are incorrect.
1124
CASE NO. GNR-E-11-03 STERLING, R (Reb) 1
6/29/2012 STAFF
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A. On pages 4-6 of Mr. Guy's testimony, he
discusses Section 304(f) and states that it is his
understanding, based on FERC Order No. 69, that Section
304(f) does not apply to QF contracts with fixed rates.
Similarly, Don Schoenbeck, on pages 36-42 of his direct
testimony, also contends that Idaho Power's proposed
Schedule 74 is not consistent with FERC's view on QF
curtailment.
For reference, 18 CFR 292.304(f) states the
following:
(f) Periods during which purchases not
required. (1) Any electric utility which
gives notice pursuant to paragraph (f)
(2) of this section will not be required
to purchase electric energy or capacity
during any period during which, due to
operational circumstances, purchases from
qualifying facilities will result in costs
greater than those which the utility would
incur if it did not make such purchases,
but instead generated an equivalent amount
of energy itself. 1
FERC's Order No. 69, in explaining the intent
of Section 304(f), stated the following:
The Commission does not intend that this
paragraph override contractual or other
legally enforceable obligations incurred
by the electric utility to purchase from a
qualifying facility. In such
arrangements, the established rate is
based on the recognition that the value of
1 (Parts (2), (3), and (4) of this section have been omitted
because they relate to notification requirements not relevant
to this discussion).
1125
CASE NO. GNR-E-11-03 STERLING, R (Reb) 2
6/29/2012 STAFF
I
1 the purchase will vary with the changes in
the utility's operating costs. These
2 variations ordinarily are taken into
account, and the resulting rate represents
3 the average value of the purchase over the
duration of the obligation. The
4 occurrence of such periods may similarly
be taken into account in determining rates
5 for purchases.2
6 A. Just recently, FERC went on to further explain
7 the proper application of Section 304(f) when it stated
8 the following:
9 55. In Order No. 69, which implemented
section 304(f), the Commission stated that
10 that section was intended to deal with a
certain condition which can occur during
11 light loading periods, in which a utility
operating only base load units would be
12 forced to cut back output from the units
in order to accommodate the unscheduled QF
. 13 energy purchases. The Commission stated
that such base load units might not be
14 able to later increase their output levels
rapidly when the system demand later
15 increased, resulting in the utility
needing to rely upon less efficient,
16 higher cost units. Section 304(f), when
read in conjunction with the relevant
17 explanation in Order No. 69, applies only
to such low loading scenarios, and cannot
18 be relied upon to curtail purchases of
unscheduled QF energy for general economic
19 reasons.
20 56. Many avoided cost rates are calculated
on an average or composite basis, and
21 already reflect the variations in the
value of the purchase in the lower overall
22 rate. In such circumstances, the utility
is already compensated, through the lower
23 rate it generally pays for unscheduled QF
24 2 FERC Order No. 69, Docket No. RM79-55, Final Rule Regarding the
Implementation of Section 210 of the Public Utility Regulatory 25 Policies Act of 1978, (Issued February 19, 1980), p. 77.
1126
CASE NO. GNR-E-11-03 STERLING, R (Reb) 3
6/29/2012 STAFF
i energy, for any periods during which it
purchases unscheduled QF energy even
2 though that energy's value is lower than
the true avoided cost. On the other hand,
3 for avoided cost rates that are determined
in real-time, such avoided costs adjust to
4 reflect the low (or zero or negative)
value of the unscheduled QF energy,
5 allowing the QF to make its own
curtailment decisions. In neither case is
6 the utility authorized to curtail the QF
purchase unilaterally.3
7
8 It is noteworthy that FERC, in paragraph 55 of the
9 Entergy Order recognized that "Many avoided cost rates
10 are calculated on an average or composite basis, and
11 already reflect the variations in the value of the
12 purchase in the lower overall rate." (Emphasis added).
13 Furthermore, FERC stated "In such circumstances,, the
14 utility is already compensated, through the lower rate it
15 generally pays for unscheduled QF energy, for any periods
16 during which it purchases unscheduled QF energy even
17 though that energy's value is lower than the true avoided
18 cost." (Emphasis added).
19 Mr. Guy's and Mr. Schoenbeck's interpretations
20 of the proper application of Section 304(f) might be
21 correct if the presumptions described by FERC in Order
22 No. 69 and in the Entergy order were correct for Idaho.
23 However, those presumptions, in fact, are not correct
24
25 Entergy Services, Inc., Docket Nos. ERO5-1065-011, 0A07-32-008;
137 FERC ¶ 61199 (F.E.R.c.) Order on Compliance Filing (Issued
December 15, 2011).
1127
CASE NO. GNR-E-11-03 STERLING, R (Reb) 4
6/29/2012 STAFF
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for Idaho.
I have been the person responsible for
computing Idaho's published avoided cost rates for the
past 18 years. Although I did not create the original
SAR model used to compute published avoided cost rates, I
have made the extensive changes to the model that have
been ordered over the past 18 years, I have maintained
the model, and I have been responsible for making all of
the avoided cost computations adopted by the Commission
since 1995. Based on my extensive experience with the
SAR model, Idaho's published avoided cost rates do not
already reflect the variations in the value of the
purchase in the lower overall rate during the specific
low loading scenarios when 304(f) is clearly intended to
U0. YJ
It is true that Idaho's avoided cost rates may
at times be either higher or lower than the true avoided
costs, but this is due to real-time prices not exactly
matching rates computed in advance for a long-term
contract. This fact is simply an unavoidable outcome of
the computation methodology, not an input assumption that
explicitly drives the result. Frequent deviations
between real-time prices and computed long-term avoided
cost rates are inevitable under any computation
methodology, regardless of whether any attempt is made to
.
CASE NO. GNR-E-11-03 1128
6/29/2012 STERLING, R (Reb) 5
STAFF
S
r
.
i account for low loading scenarios.
2 Under the SAR methodology for computing
3 published avoided cost rates, the method is based solely
4 on the estimated cost of building and operating a CCCT,
5 the surrogate avoided resource. There is clearly no
6 attempt to model low loading scenarios, or for that
7 matter, any other load scenarios. Furthermore, there is
8 no consideration for operational circumstances or
9 constraints of either the QF or the utility's other
10 generation resources, nor is there any attempt to reflect
11 actual variations in the value of the purchase in a lower
12 overall rate. Quite simply, the SAR methodology
13 considers only the CCCT surrogate, independent of any
14 other resources and system conditions, and assumes that
15 it will be operated during all hours when it is
16 available.
17 All 11 of the projects owned and operated by
18 Idaho Wind Partners have contracts containing published
19 avoided cost rates computed using the SAR methodology.
20 Therefore, there is no consideration in the rates in any
21 of these contracts for low loading conditions when
22 curtailment would be likely.
23 Q. Once avoided cost rates have been computed by
24 the SAR model, are there post-modeling adjustments
25 applied to the rates to attempt to shape them to better
1129
CASE NO. GNR-E-11-03 STERLING, R (Reb) 6
6/29/2012 STAFF
1 match variations in true avoided costs?
2 A. Yes, two types of adjustments are made. One
3 adjustment is made to shape the rates by season and the
4 other adjustment is made to shape the rates based on
5 heavy and light load hours.
6 Q. Please explain the seasonal adjustment.
7 A. The avoided cost rates computed by the SAR
8 model consist of single annual values corresponding to
9 each year of the proposed contract. The purpose of
10 seasonal rate adjustments is to shape annual rates into
ii seasonal rates that better reflect variations in value
12 during different times of the year. For example, power
13 is typically more valuable during peak summer and winter
14 months, and less valuable during spring months when hydro
is generation is cheap and plentiful. Seasonalization
16 factors are applied to the avoided cost rates computed by
17 the SAR model to either increase or decrease the rates
18 during different seasons. Seasonalization factors are
19 applied as weighting factors. For Idaho Power for
20 example, a seasonalization factor of 1.20 is applied in
21 the months of July, August, November and December,
22 thereby increasing rates by 20 percent in the utility's
23 summer and winter peak load months. Conversely, in the
24 months of March - May, a seasonalization factor of 0.735
25 is applied to lower avoided costs during the spring
1130
CASE NO. GNR-E-11-03 STERLING, R (Reb) 7
6/29/2012 STAFF
1 runoff period. During the remaining months of the year
2 (January, February, June, September and October), a
3 seasonalization factor of 1.00 is applied. For Avista,
4 seasonalization factors are applied in only two different
5 seasons of the year. For PacifiCorp, seasonalization
6 factors are applied monthly.
7 Q. Please explain the heavy and light load hour
8 adjustment.
9 A. The purpose of the heavy and light load hour
10 adjustment is to shape seasonal (or monthly) rates into
11 hourly rates that better reflect variations in value
12 during different times of the day. Heavy load hours are
.
13 those hours from 7:00 am through 11:00 pm Monday through
14 Saturday. Light load hours are the remaining nighttime
15 hours and all hours on Sundays and holidays. A
16 Commission-approved differential between heavy and light
17 load hour prices is applied to rates calculated by the
18 SAR model such that prices in heavy load hours are
19 increased and prices in light load hours are decreased.
20 There is no overall impact of the heavy/light load price
21 differential on projects with the same flat hourly
22 generation shape; however, facilities that produce more
23 or less of their generation in heavy or light load hours
24 receive payments accordingly. The current approved
25 heavy/light load hour price differential is $5.00 per MWh
1131
CASE NO. GNR-E-11-03 STERLING, R (Reb) 8
6/29/2012 STAFF
1 for Avista, $7.28 for Idaho Power, and varies on a
2 monthly basis for PacifiCorp.
3 Q. Do either of the seasonal adjustments or the
4 heavy/light load hour adjustments account for the type of
5 variation in price or the low load scenarios contemplated
6 by the Entergy Order?
7 A. No, they do not. The seasonal and heavy/light
8 load hour adjustments are solely intended to recognize
9 that the value of power generally varies throughout the
10 months of the year and throughout the hours of the day.
11 Because the SAR model only computes annual rates, both of
12 these adjustments help to shape the rates to more closely
13 match expected variation in actual market prices.
14 Clearly, however, they do not consider the dispatch of
15 any of the utility's resources, the actual real-time
16 variations in the value of power, or the utility's
17 inability to further back down base load resources or its
18 ability to ramp them back up to meet increasing load. In
19 short, these adjustments are in no way intended to
20 address pricing during those low load situations when the
21 utility might be forced to curtail generation.
22 Q. Are there any other adjustments that are made
23 to the avoided cost rates computed by the SAR model?
24 A. Yes, there is one additional adjustment that is
25 applied only to wind projects. That adjustment is a wind
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i integration adjustment that serves to decrease avoided
2 cost rates for intermittent wind generation. The purpose
3 of the wind integration adjustment is to account for the
4 additional costs experienced by the utility when it must
5 integrate wind generation with the generation produced by
6 its other generation resources. The additional costs
7 attributable to intermittent wind generation are
8 primarily the result of non-economic dispatch of the
9 utility's other resources. Wind integration costs
10 adopted by the Commission vary from seven to nine percent
ii of the avoided cost rate depending on the level of wind
12 penetration on each utility's system, and are capped at
13 $6.50 per MWh.
14 Q. Do wind integration adjustments account for the
15 type of variation in price contemplated by the Entergy
16 Order?
17 A. No, they do not. Wind integration adjustments
18 are generally determined through sophisticated studies
19 that measure the additional incremental costs incurred by
20 the utility as increasing amounts of wind generation are
21 added to the system. The studies typically involve
22 hourly dispatch modeling of the utility's entire resource
23 portfolio. The hourly dispatch simulations attempt to
24 replicate normally expected conditions, not extreme low
25 load circumstances when all base load resources are
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backed down to minimum levels. In fact, the hourly
dispatch models typically used for wind integration
studies do not have the ability to curtail QFs.
Therefore, wind integration adjustments do not account
for the type of variation in price and the low load
scenarios contemplated by the Entergy Order.
Q. Eight of the eleven Idaho Wind Partners
contracts contain what is sometimes referred to as the
"90/110" provision. Can you explain what this provision
is and whether it relates to price variations
contemplated by the Entergy Order?
A. The 90/110 rule was adopted in 2004 when the
first large scale wind QF contracts were proposed. With
the emergence of large wind projects, a question arose
about whether wind facilities, because of their
intermittent generation, should be entitled to published
avoided cost rates, tip until this time, utilities had
held that published rates were intended for "firm"
generation that was reasonably predictable. As a
condition for being eligible for published rates, the
utilities proposed that the generation from all new
facilities be subject to a requirement that the monthly
generation be predictable within a 90 to 110 percent
Case Nos. IPC-E--04-08 and IPC-.E-04-10, Order No. 29632, November
22, 2004.
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band. If the project could deliver an amount of energy
2 that was at least 90 percent of its monthly estimate but
3 not more than 110 percent of the estimate, it was
4 entitled to full published avoided cost rates. However,
5 if the facility's actual monthly generation fell outside
6 of the 90/110 percent band, it would be entitled to a
7 market-based rate for the shortfall or the excess
8 generation. The purpose of the 90/110 rule was to
9 require a reasonable level of predictability for QF5,
10 comparable to the predictability a utility could expect
if it purchased power from some other source.
12 The 90/110 rule was later abandoned for wind • 13 projects and replaced with three new requirements
14 intended to accomplish a similar goal. Three of Idaho
15 Wind Partners' eleven projects contain these new
16 requirements. Under the new requirements, in order to be
17 eligible for published rates, wind projects must maintain
18 a "Mechanical Availability Guarantee" of 85 percent, must
19 agree to pay a proportionate share of wind forecasting
20 costs, and must agree to a wind integration charge as
21 discussed earlier. As with the 90/110 rule, these three
22 new requirements are intended to ensure a reasonable
23 level of predictability in order for wind projects to be
24 entitled to "firm" or published avoided cost rates. The
25 purpose of these requirements is not to account for the
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type of variation in price based on curtailment
2 contemplated by the Entergy Order.
3 Q. What can you conclude about curtailment from
4 the way published rates are calculated and from the other
5 elements contained in the power sales agreements?
6 A. I conclude that nothing in the SAR model in any
7 way captures the variations in an overall rate that would
8 encompass circumstances described in FERC Order 69 or in
9 the Entergy Order. Furthermore, none of the provisions
10 contained in any of the Idaho Wind Partners' contracts
11 (or any other QF contracts) address or capture variations
12 in an overall rate that would encompass circumstances • 13 described in FERC Order 69 or in the Entergy Order.
14 Q. Could the SAR model be modified to consider the
15 low load scenarios described in FERC Order 69?
16 A. No, I do not believe that it could be.
17 Modeling load scenarios would require far more
18 sophistication than the current SAR model possesses. An
19 SAR model, because it is based on the costs of building
20 an operating a single, surrogate resource, is not capable
21 of considering load scenarios. I believe that it would
22 be necessary to have a model with resource dispatch
23 capability in order to model various load scenarios.
24 Q. Does this conclude your rebuttal testimony?
25 A. Yes, it does.
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(The following proceedings were had in
open hearing.)
(Staff Exhibit No. 304, having been
premarked for identification, was admitted into evidence.)
MS. SASSER: And, with that, I would present
Mr. Sterling for cross-examination.
COMMISSIONER SMITH: All right, Mr. Solander,
I'll start with you again.
MR. SOLANDER: Thank you.
CROSS-EXAMINATION
BY MR. SOLANDER:
Q. Good afternoon, Mr. Sterling.
A. Good afternoon.
COMMISSIONER SMITH: You need to turn on your
mic.
MR. SOLANDER: Sorry.
COMMISSIONER SMITH: And get closer.
Q. BY MR. SOLANDER: With regard to the IRP
methodology, is it correct that in your direct testimony, one
of the modeling inputs that you recommend be updated was the
fuel price forecast?
A. Yes.
Q. And do you agree that a price forecasting model
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1 such as AURORA uses a fuel price forecast to develop an

2 electricity price forecast?

3 A. Yes, I do.
Q. Do you also agree that a least-cost dispatch
5 model such as GRID uses both a fuel price forecast and an
6 electricity price forecast to simulate system dispatch?

7 A. Yes, that's my understanding.

8 Q. And would you agree that for a least-cost
9 dispatch model such as GRID, it would be inconsistent to update

10
fuel prices but not the electricity prices in the model?

11 A. I think in the case of GRID, it would make sense

12 to update both of those, because they are both external inputs

13 into the GRID model.

14 Q. And do you agree with the analysis that
15 Mr. Dickman presented in his rebuttal testimony where he
16 demonstrated that by not updating modeling inputs over a

17 seven-month period between May 2011 and January 2012, that

18 ratepayers would have been required to pay $27 million too much
19 over the 20-year term for a 22-megawatt wind facility?

20 A. I can't substantiate the exact figures, but I

21 agree conceptually with his analysis, yes.

22 Q. And you agree with the analysis conceptually that
23 he also did that showed that an 80-megawatt wind facility would
MIN have resulted in ratepayers paying $97 million too much over
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A. Again, I can't substantiate the figures, but I
think, again, conceptually I would agree.
MR. SOLANDER: I have no more questions for
Mr. Sterling, thank you.
COMMISSIONER SMITH: Thank you.
Mr. Andrea.
MR. ANDREA: Thank you.
CROSS-EXAMINATION
BY MR. ANDREA:
Q. Mr. Sterling, on page 46 and then over to page 47
of your direct testimony, you talk about if the Commission
deems the Utility to own the REC, then an adjustment to the
avoided cost rate is necessary because capacity and energy from
the QF simply offset capacity and energy otherwise provided by
the SAR. Could you explain just a little bit and clarify for
me what you mean by that and how that would work?
A. Well, my position on RECs is that I think, first,
the Commission has to make a decision on who owns the RECs
based on public interest criteria primarily. And then after
you decide who owns the RECs, then you deal with who wants
them, who doesn't have them, who wants to purchase them, and
what the prices should be, and how that should be handled.
I think if the Commission were to decide that --
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1 that the Utility owned the RECs in the case of a SAR type of a

2 rate, first I'd say I think it's up to the Commission to decide
3 whether any additional compensation is necessary. I think they

4 could decide either way. The suggestion in my testimony though

5 is that under an SAR methodology, it may be appropriate for a
6 Utility to make some additional payment if they wish to acquire

7 the RECs and wasn't awarded ownership of the RECs, primarily
8 because that under the SAR methodology, the rate is based on a

9 gas-fired resource which does not produce RECs. But, again, I

10 think it's up to the Commission to decide.

11 MR. ANDREA: Thank you very much. I don't have

12 anything further.
5
13 COMMISSIONER SMITH: Mr. Walker.

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

16 CROSS-EXAMINATION
17

18 BY MR. WALKER:

19
Q. Mr. Sterling, as -- as with Dr. Reading, you've
20 been -- you have in your testimony that you've been -- you've
21 been around the Commission for some time and have been, as part

22 of your job at the Commission, intimately involved in QFs and

23 avoided costs for a substantial period of time, nearly the

24 entire time of PURPA. Is that correct?
.
25 A. Yes, it's been a considerable length of time.
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Q. And is it fair to say that through this
Commission's implementation of PURPA in the state of Idaho,
that there has been an effort to -- there's been some effort
advocated by probably by the Commission and by the Utilities to
have some level of parity among the various avoided costs of
different Utilities? Is that a fair --
A. Yes, I would say we have tried to do that over
the years.
Q. What's the intent of a policy like that?
A. You mean, a policy to try to seek parity between
the rates for the various Utilities?
Q. Yes.
A. I think the primary -- the primary motivation for
that in the past has been to -- so that we don't encourage
developers to basically shop for the highest rate or flock to
one particular Utility because their rates are substantially
higher than another.
Q. And do you know, has there been -- has there been
a corresponding parity in the development of QF projects
amongst the three Utilities in the state of Idaho?
A. I'm not sure if I understand. Are you
suggesting -- are you asking if there is a difference between
the level of development, QF development, in each of the three
different Utilities' service areas?
Q. Yes.
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A. Yes, there's quite a difference.
Q. And I'd like to go to page -- page 4 -- 4 to 5 of
your direct, starting on page 4 and then those couple of
questions and answers that go to the top of page 5; starts off
on page 4, line 13: First, as a preliminary matter, do you
believe there are changes that need to be made?
A. Yes, I'm there.
Q. And to paraphrase that, basically, you
acknowledge that, yes, there is -- there has been some problems
identified through this case in the previous phases that show a
need to change something. Is that a fair --
A. Yes, that's a fair characterization.
Q. And then as you continue over on page 5,
particularly in your answer from line 4 to 15, it seems that --
is it a fair characterization to say that there is an
acknowledgment there that -- regarding some of these
disproportionate effects as far as Idaho Power's system and its
I customers by implementation of PURPA?
A. Yes, I think it's fairly clear that Idaho Power
has far more PURPA development within its service territory in
Idaho, so I think that the impact and the consequences are
consequently much greater for Idaho Power than the other two
Utilities.
Q. And you conclude that question with a proposal
that if the Commission decides to make changes to the avoided
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cost methodologies or other policies related to QF, that it
continue in this kind of parity of rates amongst the Utilities,
unless there's some clear reason for Utility-specific policies.
Is that -- that's your proposal?
A. Yes. I guess I would only add to that that, you
know, it's a balance between -- in part between ability to
administrate -- administer PURPA throughout the state if we
have different sets of rules, different processes, different
methodologies for all three Utilities, it's also a bit
difficult to administer; but at the same time, I think there
are certain things that are unique to each individual Utility,
and to the extent we can accommodate individual treatment of
Utilities within reason, I'm not opposed to that.
Q. So it's possible that you could -- you could
support under the right circumstances if Idaho Power were to
have a slightly different application of a methodology or use
of a different methodology than the other Utilities for avoided
costs?
A. Yes. And, again, I think it's a matter of
degree. I think we have, in this particular case, in our
testimony, supported some different treatment by the three
different Utilities.
MR. WALKER: No more questions, Madam Chair.
COMMISSIONER SMITH: Thank you, Mr. Walker.
MR. ARKOOSH: Thank you, Madam Chair.
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COMMISSIONER SMITH: Mr. Arkoosh.
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CROSS-EXAMINATION
BY MR. ARKOOSH:
Q. Mr. Sterling, I asked Mr. Clements --
MR. ARKOOSH: Oh, I'm sorry, ma'am. Thank you.
Q. BY MR. ARKOOSH: Mr. Sterling, I had asked
Mr. Clements whether he thought these RECs were personal
property or real property, and he didn't feel qualified to
opine. Do you --
MS. SASSER: Objection: It calls for a legal
conclusion. He's an engineer, very smart engineer, but he's
not a lawyer.
MR. ARKOOSH: I haven't asked the question yet.
COMMISSIONER SMITH: Okay, let's hear the whole
question.
Q. BY MR. ARKOOSH: Do you have an opinion regarding
that?
MS. SASSER: Objection: Calls for a legal
conclusion.
MR. ARKOOSH: That's a "yes" or "no."
COMMISSIONER SMITH: That's going to be
sustained.
MR. ARKOOSH: Well, Madam Chair, it does call for
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a "yes" or "no" answer, not what the opinion might be, and then
she can entertain the objection, but it makes a different
record.
COMMISSIONER SMITH: So ask your question again.
MR. ARKOOSH: Okay: Do you have an opinion
regarding whether it's personal property or real property?
And the answer to that question can only be "yes"
or "no." I'm not asking what the opinion might be.
COMMISSIONER SMITH: And so your objection is?
MS. SASSER: My objection is that it still calls
for him to make a legal conclusion as to --
COMMISSIONER SMITH: Well, you know, he is an
expert witness and he might have an opinion, however wrong it
may be, and, you know, depending on where your lawyer's legal
analysis takes you --
Mr. Sterling, do you want to answer that?
THE WITNESS: While I may have an opinion on a
lot of legal matters, that's one that I don't have an opinion
on. I don't know the difference between real and personal
property.
Q. BY MR. ARKOOSH: Thank you, Mr. Sterling. So the
analysis you performed was a public interest analysis, not a
state property law analysis. Is that correct?
A. I wouldn't necessarily characterize it as an
analysis. It's simply an opinion. I think it's a policy
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question primarily.
Q. So the opinion isn't even supported by analysis.
Is that your testimony?
A. I don't -- in this particular case, I don't think
it needs to be supported by analysis. I think it's primarily a
policy question.
Q. Policy is not supported by analysis?
A. Not in this particular case. I don't believe it
needs to be.
Q. Okay. Do you think that FERC intended
Section 304 to override legally-enforceable obligations it
already signed?
MS. SASSER: Objection: Calls for a legal
conclusion.
MR. ARKOOSH: Well, he certainly opined on this,
Madam Chairman.
COMMISSIONER SMITH: Mr. Sterling, if you have ani
opinion, you can render it.
THE WITNESS: Could you please repeat the
question?
Q. BY MR. ARKOOSH: Do you believe FERC intended in
Section 304 to override legally-enforceable obligations that
are already signed?
MS. SASSER: Could I ask Mr. Arkoosh to cite
Mr. Sterling to his testimony that he's referring to where
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Mr. Sterling opined?
MR. ARKOOSH: As a predicate to the question,
Madam Chairman, it's my understanding that Mr. Sterling said
there could be curtailments. Wasn't that his testimony?
COMMISSIONER SMITH: You tell us.
Q. BY MR. ARKOOSH: Well, isn't that your opinion,
Mr. Sterling: There may be curtailments?
A. I'm sorry, "There may be curtailments"?
Q. For low -- low load conditions?
A. Certainly, there could be.
Q. Okay. If that's your opinion, can those
curtailments for low load conditions apply to contracts that
are already signed?
A. That's a different question than you asked me
before, so I'll answer this particular question.
Q. Okay.
A. My answer is, yes, I believe it can, they can.
Q. And do you believe FERC intended that in passing
Section 304 or is this --
MS. SASSER: Objection: Mr. Sterling can't
testify to what FERC intended.
MR. ARKOOSH: Madam Chairman, I'd like to finish
the question. I think that's fair.
COMMISSIONER SMITH: Well, he really can't
testify to what FERC intended.
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1 MR. ARKOOSH: Okay.

2
Q. BY MR. ARKOOSH: Did you do your -- did you do

3 any analysis to come to that opinion?

4 A. Well, let me clarify. When I said I didn't think

5
this required analysis before, I thought you were talking about

6 a technical engineering sort of analysis. And the answer to

7 that is no..

8
But in terms of other types of analysis, yes, I

9 reviewed -- I reviewed FERC Rules, I reviewed FERC Orders in

10 numerous cases, I reviewed cases in other states. There was

11 quite a number of things that I reviewed.

12
Q. So having reviewed all the FERC material, do you
13 have an opinion whether FERC intended that under 304 a State

14 Commission could curtail an already-signed, legally-enforceable

15 obligation?

16 MS. SASSER: I would renew my objection to what
Norm FERC intended and what this Commission has already ruled.

18 COMMISSIONER SMITH: I think you could ask his

19 opinion, but please don't ask him what FERC intended.

20 MR. ARKOOSH: Thank you. That's fair.

21
Q. BY MR. ARKOOSH: Is it your opinion FERC

22 intended --

23 (Alarm sounds.)

24 MR. ARKOOSH: The questions aren't that bad,
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MR. MILLER: That's your signal to stop.
Q. BY MR. ARKOOSH: Is it your opinion FERC intended
that Section 304 be used by State Commissions to curtail
legally-enforceable obligations that are already signed, or do
you not have an opinion?
A. It depends upon the exact particular -- what's in
the particular contract that may have already been signed.
Q. Say it's silent on the matter.
A. Well, first, let me say that, no, I don't believe
any Idaho QF contract has been silent on the matter since late
1985.
Having said that, to the extent that a contract
is silent on the matter, I do not believe that 304(f) can be
ignored. I think it's part of the law. People who are
sophisticated developers, spending millions of dollars on
projects, should be familiar with the law as it applies to
their particular project, and whether it's expressly referred
to in a contract or not I don't believe means that it does not
apply.
Q. So, Mr. Sterling, your answer is, in your
opinion, FERC did so intend?
A. My answer was as I just stated.
Q. Well, I can't tell the answer to my question from
what you just said. In your opinion, do you believe FERC
intended to -- 304 be used to curtail already-signed,
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legally-enforceable obligations?

A. I think what FERC said was they don't intend it
3 to override any particular language that may already be in a
4 contract.
Q. Okay. And what is your opinion?
A. All I can go by was what FERC said.
Q. Okay. Thank you, sir, very much.
MR. ARKOOSH: Thank you, Madam Chair.
COMMISSIONER SMITH: Mr. Williams.
CROSS-EXAMINATION
BY MR. R. WILLIAMS:
Q. Just a couple of questions, Mr. Sterling, and my
questions relate to the Dynamis contract and your testimony on
curtailment. And just as a first question, do you -- well, let
me back up.
You reviewed the Dynamis contract when it came
through the Commission. Correct?
A. Yes, I did.
Q. And it was not an SAR-developed rate; it was an
IRP-developed avoided cost rate. Is that your recollection?
A. Yes.
Q. Now, do you believe that the Dynamis contract or,
for that matter, the current few projects out there that have
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1 IRP -calculated rates, do you think they should also be subject
to Schedule 74 curtailments?
A. Yes, I do.
Q. Now, in the Dynamis contract, it has its pricing
and it states it in its application it has a 20-year levelized
avoided cost pricing of roughly $92 a megawatt hour. Is that
in the parameters of what your recollection may or may not be

8
for that project?

9 A. I think my recollection is the contract doesn't

10 contain levelized rates.

11
Q. No, my question was I believe the application

12
filing the Dynamis contract says that the 20-year levelized
.

13 rate for that project is roughly 92 dollars and change, but --

14 A. I would agree that if the rates that are

15
contained in the contract were to be levelized, $92 a megawatt
16 hour would be approximately the right price.

17
Q. Right. Okay. So -- and in that contract, one of

18
the -- I mean, you reviewed it and you reviewed the pricing of
19 that. And would you agree with me that one of the factors that

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led to that price being at that level was the fact that Dynamis

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agreed not to operate in light load hours; or the flip side of
22 that would be if they had wanted to operate on a flat 24-hour
23 basis, they -- the levelized price for the energy would be

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less, but then correspondingly, they'd have more hours of
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1 A I would agree.

2
Q. You agree with that statement. So they gave up
3 producing during periods of time when the -- when it wasn't --

4 it was either worth nothing or negative to Idaho Power, and
5 that had the model effect in the IRP model of driving a higher
6 price during the daylight hours which had showed up in the

7 contract.

8 So if Idaho Power and Dynamis had also said that
9 an additional period of time throughout the year -- let's just

10 say another five percent of the time in light load

11 conditions -- Idaho Power also had the right to interrupt

12 Dynamis at their election, would that not also have increased

.
13 the 20-year levelized price per megawatt hour?

14 A. Let me make sure I understand that. You're

15 saying if Idaho Power would have had the rights to curtail

16 Dynamis --

17 Q. -- during their operating hours. They can

18 deliver 16 hours a day. Let's say Idaho Power said, For those

19 16 hours that you are on, we also want the ability to come in

20 and take five percent of that generation and curtail it.

21 Would that not also have had a price impact on

22 the calculation of Dynamis's avoided cost?

23 A. The AURORA analysis that I reviewed did not

24 assume any curtailment conditions for Dynamis.
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25
Q. Well it, in fact, did have absolute curtailment,
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1 eight hours of the day, 365 days a year. Correct?
A. I don't consider that a curtailment. I consider
3 that voluntary nonproduction that was mutually agreed to by the
4 parties.
5 Q. But, nonetheless, it had the impact of changing
6 the avoided cost price from when they were producing. I think
7 we've asked and answered that.
8 MR. R. WILLIAMS: So, Madam Chair, I have no
9 further questions.
10 COMMISSIONER SMITH: Thank you.
low Mr. Uda.
12 MR. UDA: Madam Chair, if I could beg your
S 13 indulgence, I have just a few questions but I think my
14 colleagues may ask them, so in the event that they don't --
15 COMMISSIONER SMITH: Certainly.
16 Mr. Miller.
lirm MR. ADAMS: I think he said no.
18 MR. MILLER: No, thank you, Madam Chairman.
19 COMMISSIONER SMITH: I didn't hear the rattling.
20 Mr. Richardson.
21 MR. RICHARDSON: Thank you, Madam Chair.
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CROSS-EXAMINATION
BY MR. RICHARDSON:
Q. Good afternoon, Mr. Sterling.
A. Good afternoon.
Q. Just an observation: Did you know that you have
more legal citations in your testimonies than are in the legal
briefs submitted by your lawyer in this matter?
A. No, I was not aware of that.
Q. On page 27 of your direct testimony, you -- at
line 6, you note some of the reasons the Commission returned to
20-year contracts back in 2002. Do you see that?
A. Yes, I do.
Q. And one of those reasons was that, quote: Longer
contracts better coincide -- the longer contract better
coincides with the amortization period or planned resource life
of the renewable or cogeneration resource being offered.
That reason is still valid today, isn't it?
A. Yes, a longer contract would -- would do just
exactly what that says.
Q. And a second reason the Commission went back to
20-year contracts was that, quote: It better reflects the
amortization period of generation projects constructed by the
Utilities themselves.
And that's also true today as well. Correct?
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1 A. Yes, it is.

2 Q. And the third reason you noted for the

3 Commission's decision to return to 20-year contracts was that,

4 quote: To provide a revenue stream that will facilitate the

5 financing of QF projects.

6 And that, likewise, is true today too, isn't

7 it?

8 A. Yes, I believe it is.

9 Q. Then you are asked on page 28 of your direct
10 testimony whether a five-year contract -- a five-year limit on
Now contract length would, quote, severely limit the ability of

12 projects to obtain financing.
.
13 And you responded that you agreed with that

14 statement. Correct?

15 A. Yes, I think it would.

16
Q. You stated that development would likely slow

17 considerably under PURPA. Correct?

18 A. That's right.

19
Q. And you note, however, that large facilities
20 could still be developed with long-term contracts in response

21 to Utility requests for proposal, just as they are in most of

22 the rest of the country. Do you see that?

23 A. Yes.

24
Q. So when Idaho Power issues a request for proposal
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25 for a new generating facility, what competitive proposal rules
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1 do they operate under?
2 A. We don't have any formal rules that they are

3 required to follow, but when they do a request for proposal
4 there is a very extensive analysis of the process, the review

5 of the bids, the criteria that was used to evaluate the bids.
6 There's a very extensive review during the process, but there

7 is no particular set of rules. There is an open docket,

8 however, to examine whether some of those sorts of rules are

9 necessary.

10 Q. Right. And that open docket, wasn't that
11 requested to be opened by the Northwest and Intermountain Power

12 Producers Coalition, along with the Idaho Irrigation Pumpers
L
13 Association, and the J. R. Simplot Company back in 2008?

14 A. I don't remember the date or all of the people

15 that requested it, but I do recall that it was something that
16 came out after the request for proposal process that Idaho

17 Power went through for the Langley Gulch project.

18
Q. And you would agree that there was some grumbling
19 about how that process went?

20 A. I suppose there were some people who had issues

21 with it. I don't know if I'd characterize it as "grumbling."
WIM I guess you could define that how you choose.

23 Q. Well, something obviously motivated the Northwest

24 and Intermountain Power Producers Coalition, the Idaho
fl 25 Irrigation Pumpers Association, and the J. R. Simplot to go
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1 through the trouble to petition the Commission to establish

2 competitive bidding guidelines, wouldn't you think?

3 A. Certainly.

4
Q. And, yet, to this date, the Commission has taken

5 no steps to move that docket forward, has it?

6 A. My recollection is that we had at least one,

7 perhaps more, workshops, and then it kind of got put on hold

8 primarily because none of the res- -- or, none of the Utilities
9 were acquiring new resources or had any plans to do so

10
immediately; and in the mean time we had at least four rate

11 cases that I can think of, and so probably all of the parties
12 who had an interest in that particular docket were also very

fl
13 occupied with other case filings, and so it was not a priority

14 at the time. But the docket is still open.

15
Q. But you would agree, wouldn't you, that
16 competitive bidding guidelines would be an advantage to the

17 development community, wouldn't you?

18 A. I don't know that I would -- I don't know that it
19 would be an advantage necessarily. It would certainly be a
20 change, and it might be helpful for more than just the QF

21 community.

22 Q. Over on page 29, you state that, quote: It would
23 be contrary to the public interest to encourage PURPA

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development, due to a lack of need and poor economic

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Do you see that?
A. What line are you reading from?
3 Q. I'll get it. Line 3.

4 A. Yes, I see line 3.

5 Q. And that's where you state that it would be
6 contrary to the public interest to encourage PURPA development

7 at a time when it is not needed to serve customers and at a

8 time when poor economic conditions strain customers' ability to

9 pay.

10 Do you see that?

11 A. Yes, I do.

12
Q. And do you recall that every single party except
.
13 for the Commission Staff and Idaho Power in the Langley Gulch

14 certificate proceeding opposed the granting of that certificate
15 based on lack of need and poor economic conditions?

16 MR. WALKER: Objection: That's irrelevant to the

:17 setting of avoided costs, of what we're here today for, and is

18 not even referenced by that portion of testimony.

19 COMMISSIONER SMITH: Mr. Richardson.

20 MR. RICHARDSON: I'm just inquiring of this
21 witness when lack of need and poor economic conditions justify
22 not encouraging a particular type of resource like PURPA or

23
like Langley Gulch. It's related to the purpose of his

24 testimony.
.
25 MR. WALKER: It's not related to the purpose of
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1 the testimony about avoided cost. It's talking about a

2 different resource.

3 MR. RICHARDSON: I'm not sure this party has

4 standing to object to my questions.

5 MS. SASSER: To the extent that I need to object,

6 I will. This portion of Mr. Sterling's testimony is speaking

7 to contract length.

8 MR. RICHARDSON: The testimony says it's contrary
9 to the public interest to encourage PURPA development at a time
10 when it is not needed and when the times are at poor economic

11 conditions.

12 MS. SASSER: In response to a question about

.
13 contract length.

14 COMMISSIONER SMITH: I think your question does

15 go far afield, Mr. Richardson.

16 MR. RICHARDSON: I'll withdraw the question,

17 Madam Chair.

18 COMMISSIONER SMITH: Thank you.

19
Q. BY MR. RICHARDSON: Going back to page 28,

20 Mr. Sterling, in the last sentence of the answer that begins on

21 line 10, you observe that with the lower rates being proposed

22 in this docket, a project would welcome the opportunity to sign

23 new contracts every five years.

24 And I thought about that statement, and I thought

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1 be betting that electric rates would go up based on our

2 collective experiences over the years, and I assumed that you
3 had that in mind when you made that statement; that is, that a

4 developer would want to sign contracts every five years because
5 perhaps the rate would be better in five years. Is that what

6 you're saying?

7 A. No, I was -- I was simply saying that if rates

B are lowered through this proceeding, that there may be lots of

9 QFs who don't want to be locked in to low rates for 20 years.

10 They may, for whatever reason, want to sign a contract now, but

11 they don't want to be stuck with that rate for the next 20

12 years. They may look forward to an opportunity to possibly

.
13 getting a higher rate five years from now or ten years or 15

14 years.

15
Q. So they'd want to sign a shorter-term contract on
16 the hope that rates perhaps go up in five years or whatever?

17 A. That's correct. And I was simply acknowledging

18 that as a possibility.

19
Q. Well, let's look at your suggestion from the

20 developer's perspective. Let's say that Joe Developer is

21 seeking a five-year contract for his dairy waste-to-energy
22 project, and Joe knows the rates are very low but he wants the

23 contract anyway. Apparently, this project pencils out for Joe

24 with only a five-year contract and these new low rates, and it

.
25 pencils out, perhaps, because he gets the fuel for free from
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1 the dairy and he may have got a really good deal on the gen
2 sets because no one else is building projects.
3
If Joe signs a five-year contract at these low

4 rates with no assurance as to what the rate will be in five
5 years and with no assurance that even PURPA will still be on
6
the books in five years, then he would be crazy if it didn't

7 pencil out and that project worked for him. Right? If he

8 signed that five-year contract, it must be a deal for him.

9 Right?

10 A. It must be if he signs the contract.

11
Q. Right.

12 A. But I think part of the point is, you know, Joe
13 doesn't have any guarantee of what his milk price is going to
14 be five years from now either but yet he takes the risk of

15 making those investments, and businesses do that daily.

16 Q. Right. So if this pencils out for Joe, then Joe
Norm would be motivated to get as long of a deal as he could,

18 wouldn't he? So a developer with a project that works at the
19 new low rates would actually not welcome the opportunity to

20 sign a new contract every five years, would he?

21 A. I know of specific projects who have deliberately
not signed long-term contracts because they think that the

23 rates are going to be higher in the future.

24 Q. Wouldn't the ratepayers actually be better off if
.
25 Joe did lock those low rates in for 20 years?
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1 A. It all depends on how those rates compare with
2 what the other alternatives are over the next 20-year period.
3
Q. It seems, to me, that if these super-low avoided
4 cost rates that are coming into play perhaps, it seems like the
5 ratepayers would be clamoring to have the Utilities sign those.
6 A. Not necessarily, not if they're not needed.
7
Q. Has Idaho Power, to your knowledge, eliminated
8 the fuel price risk for the Langley Gulch project?
9 MR. WALKER: Objection: How is that relevant to
10 avoided costs?
11 MR. RICHARDSON: Mr. Sterling speaks to risk
12 allocation, and I want to explore risk allocation with the
.
13 witness.
14 COMMISSIONER SMITH: Mr. Richardson, could you
15 please repeat the question?
16 MR. RICHARDSON: To your knowledge, has Idaho
17 Power eliminated the fuel price risk for the Langley Gulch
18 project?
19 COMMISSIONER SMITH: Well, that isn't really
20 relevant to the avoided cost.
21 MR. RICHARDSON: I'll move on to a new question,
22 Madam Chair.
23 COMMISSIONER SMITH: Thank you.
24
Q. BY MR. RICHARDSON: Who bears the fuel cost risk
25 when a Utility builds a thermal plant?
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1 A. It's shared between the Utility and the

2 ratepayers.

3
Q. And it's shared in -- specifically how?

4 A. It's -- well, portions of it eventually are

5 included in base rates, but deviation from what's included in
6 base rates is shared through the PCA.

7
Q. And Dr. Reading discusses risk in his testimony

8 and I'm not going to duplicate what he said with you today, but

9 at page 31 of your direct testimony, you observe that, quote:

10 The annual adjustment of rates for a Utility -- the annual

11 adjustment of rates for Utility-owned resources exposes

12 customers to less risk than for PURPA resources.
.
13 And I think I understand your reasoning there,

14 and correct me if I'm wrong. It goes like this: Because the

15 Utility fuel costs are trued up each year in the PCA, the

16 ratepayers enjoy the benefits of having their rates being set

17 closer to the real-time actual cost. Is that a fair

18 characterization of what you're saying?

19 A. Yes, I would say so.

20
Q. And because the markets go up and down, the PURPA
21 projects could vary from the actual market just like today when
22 we all -- many think the PURPA prices are high and relative to

23 a low wholesale market. Correct?

24 A. That's right.
.
25 Q. Now, the risk of being out of the market is not
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1 symmetrical, is it?

2 A. You'll have to give me more explanation than

3 that.

4 Q. Certainly. The risk the ratepayer is exposed to
5 by a 20-year PURPA contract with an eight-cent rate is no

6 greater than eight cents, is it? The markets could go to zero,

7 we're paying this project eight cents, unless, of course, the
Utility starts paying people not to take power. But the market

9 risk is just eight cents. Right? Because if the market is

10
higher, then the ratepayers are in the money?

11 A. I'm not sure I'm tracking with your example.

12
Q. What I thought you were saying is that the fuel
[IJ
13 cost risk for a Utility-owned resource is less for the

14 ratepayers than a PURPA resource. I thought we said that the

15 reason for that was we true up the fuel costs for the

16
Utility-owned resource every year. Right?
A. That's right.

18
Q. And the reason that reduces risk is what?

19 A. Because the rates that are being passed through

20 to ratepayers are actually closer to what the value of that

21 energy really is.

22
Q. And with a PURPA project, what's the risk?

23 A. It depends on what the rates for the PURPA

24 contracts are compared to what the rates are for other

n 25 alternatives. We've had -- and it can go both ways. We've had
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many instances this year of actual negative prices in the
market. We have instances, not recently, but we frequently
have instances where market prices are quite high, in some
cases extremely high.
So just because your PURPA rate is fixed doesn't
mean there's no risk associated with it. There are still those
opportunities - you're still exposed to the market and the
risks of other alternatives -- that are caused by other
alternatives.
Q. And don't get me wrong, I was not suggesting in
any way that there was no risk. I didn't say it was zero. I'm
just trying to understand the asymmetrical nature of the risk.
A. If it was more symmetrical, then we would true up
PURPA rates annually, and we don't. We stick with whatever is
in the contract and we live with it. Whether it's too high or
too low, we stick with it for 20 years. Whereas, for a
Utility-owned resource, at least the fuel portion of that rate
is trued up every year. That's why I say there is actually
more risk with a PURPA project.
Q. On page 36, on a new topic, you begin your
discussion of the curtailment of receipt of generation by Idaho
Power, and you note that Schedule 72 currently allows
curtailment -- over to the top of page 37 -- for safety or
adverse effects on the Company's equipment or personnel or
service. Do you see that?
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1 A. Yes.

2 Q. You also noted that this curtailment right is
3 embedded in the power purchase agreements with the QF.

4 Correct?

5 A. What line are you referring to?
6 Q. That would be on page 36 at line 19.

7 A. Well, I don't say that it's embedded. I say that

8 I think Idaho Power has the authority to curtail under the

9 terms of all PURPA agreements.

10 Q. I'm sorry?

11 A. The language can speak for itself. I just didn't

12 use the word "embedded," like you.
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13 Q. Right. But the Schedule 72 is -- allows the

14 Utility to curtail under those certain restricted events, as
15 well as the terms of all power -- PURPA power purchase

16 agreements. Correct?

17 A. Yes.

18
Q. Now, you've obviously done some legal research

19 into this curtailment issue, haven't you?

20 A. I've done my own personal research. I'm not an

21 attorney and don't represent myself as one.

22 Q. No, but you've read the FERC Orders, you've read
23 the FERC Rules?

24 A. That's right.
.
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Q. So forgive me, I call that legal research.
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A. If you want to call it that, that's fine.
Q. And at line 21 at page 37, you note that the
newly-proposed Schedule 74 has the ability for Idaho Power to
curtail for system efficiency reasons and economic reasons.
Correct?
A. Where are you on page 37?
Q. Line 21.
A. Okay, I'm with you.
Q. And you noted that curtailment for those reasons
we discussed earlier is not allowed under the current Schedule
72. Correct?
A. That's right.
Q. And we also observe back on page 36 that the
curtailment rights in addition to being embedded in Schedule 72
are also embedded in the power purchase agreements?
A. That's correct.
Q. So you would agree that the newly-proposed
curtailment rights are also not allowed by the existing power
purchase agreements?
A. No, I didn't state that.
Q. And while you were researching the legal issues
surrounding Idaho Power's proposal, were you only looking for
indicators that would help Idaho Power's case, or were you
looking skeptically to understand all of the relevant arguments
on both sides?
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MS. SASSER: Objection: Argumentative.
MR. RICHARDSON: I'll rephrase it.
COMMISSIONER SMITH: I think the witness is
capable of characterizing the nature of his research, so I'll
allow the question.
THE WITNESS: Please repeat the question.
Q. BY MR. RICHARDSON: As you were researching the
legal issues surrounding Idaho Power's proposal, were you only
looking at indicators that would help Idaho Power's case, or
were you looking skeptically to understand the arguments on
both sides?
A. Absolutely not.
COMMISSIONER SMITH: That's a two-part question,
Mr. Sterling.
MS. SASSER: Clarify, would you?
COMMISSIONER SMITH: You better maybe ask it -- I
think "absolutely not" referred to the first question.
THE WITNESS: Referred to the question.
COMMISSIONER SMITH: And then you can ask your
second.
Q. BY MR. RICHARDSON: And I'll assume an
"absolutely" answer to the second part?
A. No, please ask the second part again,
Mr. Richardson, please.
Q. Yes, I'm finding my place.
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1 Or were you only looking at any indicators to

2 help -- that would help Idaho Power's -- or were you looking
3 skeptically to understand the arguments on both sides? That

4 was the second part.

5 A. Except for using the word "skeptically," I would
6 say, yes, I was looking at both sides.

7
Q. Thank you. And as you were researching the

8 issues surrounding Idaho Power's proposal, did you come across
9 a concept commonly known as the sanctity of contract?

10 A. No, but I think I know what the terminology

11 refers to.

12
Q. And you note that Idaho Power is already
.
13 curtailing projects even though Schedule 74 hasn't been

14 approved, on page 37?

15 A. Yes, I am aware of that.

16
Q. And then you state that, quote: It would be

17 desirable if the curtailment procedures are contained in a

18 Commission-approved tariff.

19 Do you see that?

20 A. Yes.

21 Q. Isn't it more than just desirable that this

22 state-sanctioned monopoly conduct its business pursuant to
23 Commission-approved tariffs?

24 A. Would you please repeat that?

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Q. Isn't it more than just desirable that this --
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isn't it more than just desirable that this state-sanctioned
monopoly conduct its business pursuant to Commission-approved
tariffs?
MS. SASSER: Objection: The witness has stated
what his opinion is in his testimony.
COMMISSIONER SMITH: Mr. Richardson, I think that
calls for a legal conclusion, so he doesn't have to answer.
Q. BY MR. RICHARDSON: Mr. Sterling, do you have an
opinion as to whether or not Utilities must follow tariffs in
setting rates and conducting their business?
A. Yes, I do have an opinion.
Q. And what is that opinion?
A. Obviously, they must follow the tariffs that are
approved by the Commission.
Q. And it doesn't concern you more than to just
say -- than to comment that it would be desirable for this
Utility to have a tariff for this service?
A. I'm not sure what the question there is.
It certainly would be desirable to have a tariff,
but it's a tariff that covers a Federal Rule, and I think a
tariff would certainly add clarity to implementation of the
Federal Rule. Simply if we don't have a tariff doesn't mean we
can ignore the Federal Rule. We still are obligated to follow
that, Utilities are.
Q. And you know, based on your research of the
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1 Federal Rules, that this Commission is obligated to implement

2 that Federal Rule?

3 A. Yes, we are.

4
Q. And you also state that Schedule 74 should apply
to existing, as well as new, QF contracts.
6 And legal entitlements aside, how do you think

7 Wall Street is going to view these projects if Idaho Power can

8 curtail deliveries from them?

9 A. I think it would be viewed as a business risk,

10 like all other businesses face risks.

11
Q. And in your earlier discussion with another party

12 you talked about RECs, and I appreciate you said that you

.

13 thought the Commission had to decide who owned them. Is that
NXIM right?
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A. I said my position is I think the Commission
first needs to decide the ownership question based on public
policy.
Q. And then you also said that if the Commission
finds that the Utilities should own them, that the parties
should come up with a price and for SAR-created RECs?
A. If the QF wants to obtain them, then the QF would
have to pay the price to obtain them. If the Utility is deemed
to own them, it's up to the Commission to decide whether some
price should be required that is separate from and in addition
to the avoided cost rate.
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Q. So how would you propose the Commission would go
about setting the price for the RECs?
A. I didn't make a specific proposal, and, quite
frankly, I think that is something that would be quite
difficult.
Q. But you do think it would be the Commission's
role to do that?
A. To decide ownership or to establish a price?
Q. I think you've already said that you think the
Commission should decide ownership.
A. Right.
Q. So the question is: And you think the Commission
should set the price?
A. I didn't say that either. I think somehow a
price needs to be established. It could be set by the
Commission. It could be a negotiated price that's mutually
negotiated between the parties. There's probably multiple ways
of establishing price.
Q. But there should be some compensation, in your
mind?
A. In what circumstance?
Q. If the Utilities were acquiring the RECs from the
developers.
A. Not necessarily. I said there -- it's up to the
Commission to decide if some compensation should be required,
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and I think there are arguments to be made both ways and I see
no reason or no impediment for the Commission to make a
decision either way.
Q. Okay. Were you here yesterday when I handed out
Exhibit 520, which are Staff's comments in Case IPC-E-10-22?
A. Yes, I was.
Q. Do you happen to have a copy of that with you?
A. I don't believe I do.
Q. I think we can make a copy available.
A. Okay, I have a copy.
Q. Do you recognize this document?
A. Yes, I do.
Q. And this is Staff's comments in a case where
liquidated damages was discussed by the Staff?
A. Yes, it was.
Q. And if you'll look on the last page, page 6,
there's a line that says: Technical Staff, Rick Sterling.
Is that you?
A. Yes, it is.
Q. And what does that mean to be technical staff on
Staff's comments?
A. That generally means the technical staff is the
Staff person who was primarily responsible for preparing the
comments.
Q. And were you the Staff person primarily
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1 responsible for preparing these comments?

2 A. Yes, I was, yes.

3 Q. So did you write these comments?

4 A. Yes, I did.

5 Q. So they reflect your view of the subject matter
6 to which they address?

7 A. That's correct.

8 Q. Would you turn to page 5 and read the full
9 paragraph above the heading Recommendations?

10 A. It's quite a lengthy paragraph, Mr. Richardson.
11 Would you prefer to read it?

12
Q. No, I wouldn't prefer to read it. I would like
.
13 you to read it into the record.

14 A. "Nonetheless, the proposed settlement eliminates

15 the uncertainty and additional cost and resources necessary to
16 litigate the termination of the agreement and validity of the

17 delay liquidated damages. While Staff would normally be

18 reluctant to recommend approval of a settlement that appears

19 inconsistent with the express terms of the contract, Staff

20 recognizes that the current circumstances may support

21 acceptance of the proposed settlement. Currently, electric
22 market prices are far below the avoided cost rates specified in

23 the contract. Consequently, the actual damages to Idaho Power

24 as a result of contract default are likely minimal and, in

25 fact, Idaho Power could arguably be better off because
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Yellowstone has defaulted. The terms of the proposed
settlement acknowledge some liability for Yellowstone's default
while also acknowledging some uncertainty about the actual
amount of damages to Idaho Power. Approval of the proposed
settlement will also avoid litigation. Consequently, Staff
believes that the proposed settlement is in the public
interest."
Q. And in your testimony, on page 35, you testify
that you support Avista's liquidated damages provisions. Can
you reconcile your statement here that in falling markets,
actual damages to Idaho Power as a result of a contract
default, that Idaho Power could arguably be better off? I'm
assuming that's because you're -- why would that be? Why would
Idaho Power be better off in the event of a contract default?
A. In this particular case?
Q. Uh-huh.
A. Because current rates are -- current market rates
are so far below the rates that would have been in this
contract had it proceeded.
Q. And so you're familiar with the concepts that
have been on liquidated damages discussed here for the last two
days, that sort of the dueling battle between a mark to market
methodology and a fixed security, liquidated security, for
liquidated damages? You're generally familiar with that
discussion here today?
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1 A. Yes.

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Q. So correct -- help me understand how it was not

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inconsistent for you to say that the Avista proposal is
reasonable and then, in another docket, use what is essentially

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the mark to market provision. Those seem to be polar opposite.

6 A. Well, first, I'd say that every case has its own

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unique set of circumstances, as did this particular case that

8 you've asked me to read the paragraph of. The proposal to
9 continue to apply $45 per kW as a liquidated damages security

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deposit is intended to be a proposal that would be generally

11 applied for all Utilities, for all contracts, and it's not

12 specific to any one individual contract or circumstance. It's

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13 something that I presume would have some long-lasting life to

14 it.

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And those circumstances certainly change over
16 time. We have circumstances -- and when market prices far

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exceed the rates in a PURPA contract, there has been times when

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they greatly exceeded the rates in a contract. We have

19 circumstances like we do today where the reverse is true.

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So when I look at policies, I'm looking -- I'm

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looking at a much longer term than I am in a specific instance

22 of a particular contract default.

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Q. So you noted that each circumstance is different,

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And the $45 right now is way above market, isn't it?
A. Not exactly. The $45 is a liquidated damages
security deposit. It doesn't directly relate to the market
prices. Market prices are dollars per kilowatt hour, dollars
per megawatt hour. It's kind of an apples to oranges sort of a
comparison.
Q. But we could agree that markets today are very
low relative to history?
A. We can agree to that --
Q. Wholesale electric markets?
A. -- but damages are intended to compensate -- or,
to compensate the Utility for damages, not just today but these
are 20-year contracts typically, almost exclusively 20-year
contracts.
So how many years into that 20-year contract do
you start tabulating damages? Is it just today? Just for the
next month? Just for the current year? Or do you try to
estimate damages over the 20-year life of a contract?
And that's why it's very difficult to make a
direct comparison.
Q. So if my project doesn't come online on time, say
I'm 90 days late, the Utility would be allowed to assess me
this -- assess this $45 delay security deposit or I would
forfeit it, and then I came online a month later. We would
have 30 days -- well, 120 days of damages, but the Utility
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would have recouped 100 percent of that $45 a kW. How is that
related to the Utility's damages?
A. Well, first of all, I guess in your example,
typically 90 days would not be enough period of time to elapse
before the damages would be assessed.
But that aside, I would admit that if it was --
if it was possible to accurately use a mark to market approach,
I don't necessarily have an objection to that. The problem is,
like I described, is that you look at the damages for -- it's
not just the period of time that the project has failed to come
online, it may be another period of time before the Utility can
recover from the damage. There may be more than just -- in
this case, I don't know if you specified 90 days or whatever.
The damages may go beyond that. And it may be a little bit
difficult to assess.
So, again, I'm not necessarily opposed to an
actual damages type of an approach if it could be done
practically and fairly.
Q. Well, you did it in the Yellowstone case. You
proved that it can be done practically and fairly?
A. Well, it was a settled amount in the Yellowstone
case and we were not a part of that settlement, so I don't know
how they -- quite honestly, I don't know specifically how they
arrived at that specific amount --
Q. But it's possible, isn't it --
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A. -- but it was a settled amount.
Q. -- in the case of every single QF contract for
the parties to come to an understanding of what their actual
damages would be for failure to perform?
A. It may be possible, but I don't know that it's
easy.
Q. Isn't that sort of between the Utility and the
developer to worry about that?
A. Yes, but it's one of those kind of things that I
spend a great, great deal of my time, as do you, dealing with
complaint cases, and to the extent that we cannot have to deal
with every issue like this in the form of a complaint case, I'm
supportive of that. Again, while it may be possible to deal
with that in every case of contract default, it's not my
preference to have to deal with it that way.
Q. I understood. Thank you, Mr. Sterling,
appreciate our time this afternoon.
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Madam Chair.
Madam Chair.
MR. RICHARDSON: Thank you, Madam Chair.
COMMISSIONER SMITH: You're welcome.
Ms. Nelson.
MS. NELSON: No questions. Thank you,
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: Yes, I do have some questions,
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1
CROSS-EXAMINATION
2

3 BY MR. OTTO:

4
Q. Good afternoon.
A. Good afternoon.

6
Q. There we go, that's better. Mr. Sterling, I'm

7
going to ask you some questions about pages kind of 39 through

8
42 of your testimony, and that's where you discuss RECs. So

9
I'll give you a moment to turn to those pages, and specifically

10 I'm going to start on page 40.

11
On page 40, about line 10, you describe why you

12
think there needs to be rules, and that's -- I'm quoting you --
.
13 "to ensure consistency and avoid disputes"?

14 A. I see that.

15
Q. Would you agree that there's more than one

16 resolution to this issue that will ensure consistency and avoid

17 disputes?

18 A. You'll have to expand on that. I'm not sure whati

19 your question is.

20
Q. Well, you recommend one possible solution, and my

21 question is, in your mind, wouldn't ensuring consistency and

22 avoiding disputes also be accomplished by other possible

23 suggestions?

24 A. You mean suggestions other than my own?
.
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Q. Yes.
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A. Certainly.
Q. So then you testified or in response to I think
Mr. Andrea's questions that your reasoning on -- well, first,
that the Commission should decide if they want to address RECs,
and, second, your reasoning on who should -- who they should be
allocated to is based on public interest?
A. I think, personally, I believe that should be the
primary criteria for deciding ownership.
Q. And then you provide on pages -- page 42, you
describe what I think and what I see out of your testimony is
basically two reasons, public interest reasons, that support
your recommendation, and I believe the first one is captured in
the first paragraph of your answer on 42 -- or, sorry, the
second paragraph, on line 18, where you say: Idaho is not in a
situation where renewables development is stalled or needs to
be accelerated.
Is that one of your public interest rationales?
A. Yes, it is.
Q. Did you consider any other public policy
rationales that -- to support or -- any other public policy
rationales that are impacted by who owns RECs?
A. I don't recall.
Q. So did you -- for example, did you consider
impacts to a local economy from QF development?
A. No.
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Q. Did you consider national environmental -- or,
national energy policy goals?
A. No.
Q. Would you concede that those are valid public
interest criteria?
A. They are, but I don't think that REC ownership
necessarily dictates. I think those goals could be achieved
with multiple ways of handling RECs. I don't think that
assigning REC ownership to the QF necessarily is the only way
to achieve those goals.
Q. So that leads to maybe a broader question:
What's your understanding of why renewable energy credits
exist?
A. I've -- well, I think there's a couple of
reasons:
I think initially they were conceived as a way
to -- for those who chose to pay extra to promote development
of renewable resources. And then succeeding that, it led to
renewable portfolio standards in various states where it became
a mandatory market.
So I think initially it started as a voluntary
way for people to help promote renewables, and it evolved into
a combination of voluntary and compliance markets where a state
had a particular desire to promote increased renewables
development.
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Q. That seems like a fair characterization. So I
guess to sum up this point of your criteria, that kind of Idaho
is not in a situation where renewables need to be accelerated
or stalled -- well, strike that. I'm going to move on.
You offer a second rationale, and that is in the
next paragraph that begins on line 20 of page 42 and flows over
to the next page. And essentially how I read that is a
hypothetical situation of a renewable portfolio standard either
in Idaho or a federal standard. Is that a fair
characterization of that paragraph?
A. Can you repeat that? I'm not sure I followed it.
Q. How I read that paragraph is you exploring a
hypothetical situation of a renewable portfolio standard being
a requirement of Idaho Utilities and how RECs would play into
that situation.
A. In a general way, I guess I would agree.
Q. But it's a hypothetical. Right? We don't have a
renewable portfolio standard in our state. Would you agree?
A. That's correct, we don't.
Q. Do you have any idea or indication if Idaho would
ever have one?
A. No, I don't.
Q. Do you have any idea or indication if the
national government would ever adopt one?
A. No, I don't.
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Q. If they did adopt one, do you have any idea what

2
Idaho Power's or any of the other Idaho Utilities' compliance
3 obligations would be?

4 A. It would depend upon the specifics of the

5 requirement.

6
Q. So we wouldn't know whether, say, the existing
7 hydro plants might count towards compliance?

8 A. Without the standard, we wouldn't know in

9 advance.

10
Q. So the second public interest criteria that you

11 apply for your -- to back up your suggestion that RECs should
go to Utilities is just based on a pure hypothetical that you
13 really have no idea whether it will ever happen and what the

14 actual impact will be?

15 A. No, but clearly it's been discussed in numerous

16
forums that perhaps at some point, there could, in fact, be an

17
RPS requirement, and in Idaho it probably would be a federal

18
requirement before it would ever be a state one, but the

19 possibility is certainly discussed on a regular basis and it's

20 a real possibility.

21
Q. So why is a hypothetical discussion a persuasive
MM basis on which to make public policy recommendations?

23 A. I think we do that all the time. We look into

24
the future to see what we think might happen or what's likely
25 to happen, and plan for it accordingly in a reasonable sort of
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way.
Q. I appreciate how you said "likely," and I guess I
would just -- I think we already discussed how likely that
policy situation would be.
I'm going to move on to then another section of
your testimony, begins on page 43. You discuss at length
FERC's American Ref-Fueling (sic) case. Since you walked into
the door to -- walked in the door of interpreting the case, I'm
going to explore your understanding of that case. I don't
think that's -- you decide to play lawyer, let's explore
this.
A. I clearly -- I made it clear I'm not an attorney,
and I think most people in the room recognize that, so --
Q. Right. Well you --
A. I'm not playing a lawyer.
Q. You can't hide behind not being a lawyer but put
legal analysis in your testimony.
MS. SASSER: Madam Chair, I would ask that
Mr. Otto ask a question of the witness.
MR. OTTO: I'm more than happy to ask the
question. I was just responding to Mr. Sterling's comments.
COMMISSIONER SMITH: Are you setting up for a
motion to strike, Mr. Otto, or what's the purpose of those
comments?
MR. OTTO: Madam Commissioner, I'd rather not
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1 strike the testimony. I just would like to ask one or two
2 questions and explore his understanding of the case.
3

COMMISSIONER SMITH: Sure. Then ask a question
and not make a comment.
5 Q. BY MR. OTTO: So you, on page 45, line 15, you
6 have a sentence that begins with "I believe a reasonable
7 interpretation of FERC's Order is that contracts under PURPA,
8 absent express provisions, do not convey RECs to either party,
9 nor do they dictate REC ownership."
10 So based on that, what's your opinion of what are
11 REC5 in Idaho?
Irm A. I'm confused by the question. I don't know how
.
13 that relates to the testimony that you just read.
14 Q. Well I'm just asking, based on this sentence, how
15 do you then -- what conclusion does that lead you to? They
16 don't -- you say it doesn't convey RECs to either party, so
Norm what are they?
18 A. You're going to have to clarify that question
19 more, because I'm still confused by it.
20 Q. Well, I think I'll stand with just that as the
21 answer.
WM I'm going to ask on page 46, and this is when you
23 get into pricing and I think this is a --
24 So you recommend under the IRP methodology that
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A. I didn't say, "Any amount of money."
Q. The value of the RECs will be captured in the
avoided cost?
A. Yes, I would agree.
Q. So is it your recommendation that the Commission
adopt an avoided cost methodology that includes more than just
a capacity and energy?
A. No. And the distinction that I make is I think
FERC has made it clear that avoided cost rates are only
intended to compensate for the value of capacity and energy.
To the extent that any compensation by either party may be
required for RECs, I see that as an entirely separate
transaction. It may be covered in the same contract, but it's
not part of the avoided cost rate. It may be part of a PURPA
contract, but it's not part of the avoided cost rate.
Q. So on page 46 of your direct, beginning on line
16, you say: Consequently, the cost of RECs would already be
accounted for in computing avoided costs using the IRP
methodology.
So are those costs accounted for or are they
not?
A. Well, what I've intended to imply by that
statement is that no additional compensation would be
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necessary.
Q. Would you agree that RECs have value?
A. Certainly.
Q. So you -- recommendation is that the Commission
assign a right or property that you acknowledge is valuable
without providing any value?
A. No. My position would be that the Commission
could decide that ownership starts and ends with the Utility,
that the QF never possessed them to begin with.
Q. One last question: Along with public interest,
do you believe the Commission's Decision should comply with
Idaho state law?
A. Certainly.
Q. Thank you.
MR. OTTO: That's all I have, ma'am.
COMMISSIONER SMITH: Thank you, Mr. Otto.
I think that was everyone. Mr. Uda.
MR. UDA: I'm sorry, my colleagues bilked me
again.
COMMISSIONER SMITH: I have no comment.
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WM CROSS-EXAMINATION
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•
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Q. Good afternoon, Mr. Sterling.
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1 A. Good afternoon.

2
Q. I'm Mike Uda. I represent Mountain Air Projects.
3 And I really mostly wanted to follow up with you on some of the
comments you made earlier about business risk.
5 When was Schedule 74 proposed?
6 A. I believe it was proposed in Ms. Park's direct

7 testimony in this particular case.

8
Q. Would that have been this year? Last year?

9 A. I believe it was January 31st is what was said

10 this morning.

11
Q. I think you're right. So prior to the documented

12 proposal of Schedule 74, if a qualifying facility had evaluated
.
13 its business risk, it would have been primarily looking to

14 18 CFR 292.304(f). Correct?

15 A. Yes, I presume so.

16
Q. And would you agree with me that reasonable

17 people could look at 18 CFR 292.304(f) and disagree as to its

18 meaning?

19 A. Certainly.

20
Q. So at that point, is it possible for a prudent

21 qualifying facility developer that's trying to evaluate the

22 risk along with its lenders to have looked at 18 CFR 292.304(f)

23 and conclude that it read differently than what Idaho Power has

24 proposed in Schedule 74?

25 A. That's certainly possible.
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Q. Okay. And would you further agree with me that

2 prior at least to the proposed Schedule 74, there were

3 qualifying facilities in Idaho who had to evaluate that risk?

4 A. Well, I don't know whether they did or not. The

5
fact is I don't believe that Idaho Power ever curtailed a QF
6 until probably a year ago, so prior to that time, I would have
7 been quite surprised if anyone would have given it very much

8 attention.

9
Q. So you would agree with me that prior to that

10 time, perhaps they did or they didn't, but they had to enter
into financing arrangements based on a certain revenue stream.

12 Is that correct?
.
13 A. I assume so, yes.

14
Q. Okay. And would you agree with me that based on

15
the testimony we've heard here in the last two days, that under
16 proposed Schedule 74, there could be curtailments of up to five

17 percent or more of the output of these qualifying facilities?

18 A. Well, that was an Idaho Power witness's

19 testimony.

20 Q. Right.

21 A. Which I was here for.

22
Q. And would you agree with me that under those

23 circumstances, that that would reduce the revenue that was paid

24
to those qualifying facilities who entered into contracts prior

[1
25 to the proposed Schedule 74?
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A. Yes, presumably it would reduce their revenue.
Q. Okay. And you were present for Mr. Looper's
testimony when he testified as to the effect of having the
five-percent reduction revenue to facilities?
A. Yes, I was.
Q. Do you agree with his testimony?
A. Which particular part of his testimony?
Q. The part where he said it would be disastrous for
his facilities. I think I'm loosely characterizing his
testimony.
A. I couldn't offer an opinion on that.
Q. Now, I want to explore a little bit this REC
ownership thing because this isn't really my bag, so if I get
outside the bounds, I'm sure someone will correct me. Looking
at you, Idaho Power. No, I'm kidding. Actually, I guess it's
you guys or you guys. It's one of these guys.
MR. R. WILLIAMS: I would, if you like.
MR. UDA: Help me out.
Q. BY MR. UDA: Anyway, so when you talk about this
public policy question about who owns the RECs, as I understand
your testimony, your belief is that the Utilities ought to own
the RECs. Is that correct?
A. Yes.
Q. Okay. So when you say the Utility owns the RECs,
does that mean that it goes completely to the ratepayers, or
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1 does that actually, some percentage of that, end up going back
2 to the Utility?
3 A. That's something that would have to be

4 determined.
5
Q. Okay. Well, maybe I can refresh your
6 recollection. As part of the Idaho Public Utility Commission

7 Staff, were you part of the Staff team that submitted comments

8 in Docket IPC-E-12-17, which is the Idaho Power Company's
9 Application for authority to implement power cost adjustment

10 rates for electric service from June 1, 2012, through May 31,

11 2013? I guess it was filed or submitted, received by the

12 Commission anyway, on May 15th of this year.

13 A. No, I wasn't part of that, but perhaps I could

14 help get at some of your question.

15
Q. Okay, if you don't know the answers to this, this

16 is fine, I could refresh your recollection. But if you weren't

17 involved in the preparation of this document --

18 A. Well, I can't say with regard to RECs in the PCA.

19
The current practice and past practice has been

20
that to the extent at least Idaho Power -- I believe that was

21 an Idaho Power case that you cited -- to the extent Idaho Power

22 receives revenue from the sale of RECs, those have been passed

23
through the PCA, and although I don't recall whether they're

24 subject to sharing.
.
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Q. May I --
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HEDRICK COURT REPORTING STERLING (X)
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MR. UDA: Can I use your assistance?
MR. ADAMS: Sure.
MR. UDA: I don't have any exhibits and I'm not
sure exactly about the numbering system here, but this would be
Mountain Air's exhibit, its first one, whatever that number
would be.
COMMISSIONER SMITH: Mr. Uda, your number would
be 2301.
(Mountain Air Projects, LLC, Exhibit No.
2301 was marked for identification.)
Q. BY MR. UDA: Whenever you're ready.
A. I'm ready.
Q. Okay. I wanted to turn your attention to page 7
of I guess what's been identified as 2301 from this Comments of
the Commission Staff, and turning specifically to Paragraph 9
on page 7.
A. Yes.
Q. Are you there?
A. Yes, I am.
Q. Okay. And the last sentence there, would you
agree with me that the amount included in the deferral balance
was -- for sale of RECs -- was $5,521,597?
A. I would.
And if I could, just to answer the previous
question because it is contained in that paragraph, REC
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HEDRICK COURT REPORTING STERLING (X)
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• 1 1 revenues have been subject to sharing and jurisdictional

2 allocation.

3 Q. And on Attachment C, if you would turn to the

4
back of the Staff Comments -- I'm hoping it's been marked on
5 your page so that you can find it, because my eyes are
6 terrible -- it says this is line item for renewable energy

7 credit sales.

8 COMMISSIONER SMITH: He's on Attachment C, page 11

9 of two.

10 MR. UDA: Yes, page 1 of two.

11 MS. SASSER: Madam Chair, if I can object, I'm

12 not sure what the relevance of the Commission's treatment of
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13 these RECs is, and I'm also not sure what part of

14 Mr. Sterling's testimony Mr. Uda is cross-examining.

15 COMMISSIONER SMITH: Mr. Uda.

16 MR. UDA: Well, I mean, I guess there's two

17 things.

18 I mean, one is, you know, the witness has

19 testified that it's his belief that the Utilities ought to own

20 the RECs. And what I'm exploring is, you know, what is the

21 consequences of that, because yesterday we heard from the
22 witness from Idaho Power that all of the benefit of the RECs
23 went back to the ratepayer. And so I'm just trying to make

24 sure the record is clear on that.
.
25 And I think the second purpose of what I'm
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HEDRICK COURT REPORTING STERLING (X)
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attempting to do here is to show an incentive for the Utilities
to own the RECs, because they're making revenue from it and
it's not a revenue neutral decision to them.
COMMISSIONER SMITH: So, Ms. Sasser, I'm going to
overrule the objection, allow the witness to answer.
But I think, Mr. Uda, you've gotten the answers
to those questions already.
MR. UDA: Well, I guess if I can just move for
the admission of the exhibit, we can let the exhibit speak for
itself and move on.
COMMISSIONER SMITH: Okay. Without objection, we
will admit Exhibit 2301.
(Mountain Air Projects, LLC, Exhibit No.
2301 was admitted into evidence.)
MR. UDA: Let me just examine my notes for a
minute, Madam Chair, and I think I'm finished.
Q. BY MR. UDA: Well, I remember one more question I
have for you, Mr. Sterling:
You testified earlier I think in response to
questions from Mr. Richardson that the reason -- I think at
least one of the reasons you had a preference for having this
fixed charge for delay damages or whatever you're calling your
security deposit was because it would reduce disputes.
My question to you is if you have existing QFs in
the state of Idaho who were not aware of even the existence of
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proposed Schedule 74 nor should they have been reasonably aware
of Idaho Power's interpretation of 18 CFR 292-304(f), assuming
the Commission has jurisdiction over those disputes, do you
think you're going to see a lot of disputes over that?
A. I don't know. It's --
MR. UDA: No further questions.
COMMISSIONER SMITH: All right.
Do we have questions from the Commissioners?
COMMISSIONER REDFORD: No.
COMMISSIONER KJELLANDER: No.
pirm EXAMINATION
13
14 r BY COMMISSIONER SMITH:
15
Q. Well, Mr. Sterling, unfortunately, I do.
16
Looking at page 6 of your testimony, it seems, to
17 me, that you have hit on some key concepts that perhaps the
18
Commission has, well, I'll just say failed at in the past. On
19 line 7, you note that this whole SAR methodology requires some
20 vigilance. Is that correct?
21 A. Yes, that is correct.
22 Q. And it occurs, to me, that much of the cases
23 that -- many of the cases that have come before the Commission
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HEDRICK COURT REPORTING STERLING (Corn)
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vigilance. Would you agree or disagree with that?
A. I wouldn't entirely agree with that. I think
part of the -- part of the difficulty that we have had in the
recent past -- and by "recent past," I mean the past several
years -- first of all, we switched to a gas-fired surrogate
avoided resource back in about 1995 or '96, and when we did
that, much more of the avoided cost rate under the SAR
methodology became tied directly to natural gas price. And
natural gas price has been quite volatile at times, and we have
relied on forecasts that we don't produce from other parties,
and those forecasts that we have been relying on from the
Northwest Power and Conservation Council has not been updated
frequently or on a regular schedule. And so some of that has
been beyond our control.
We have certainly been very vigilant in updating
our rates when those forecasts change, but we don't control the
timing and frequency of when those forecasts have been
produced, and that's caused some difficulty for us in keeping
our avoided cost rates where they should be.
Q. So on line 18, you talk about keeping fuel prices
and other assumptions used in the model updated. How often do
we need to do that in order to exercise the correct degree of
vigilance?
A. Well, for things like fuel prices, I think we
need to do it annually.
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HEDRICK COURT REPORTING STERLING (Com)
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For other variables that may be used, whether
it's in the SAR methodology or an IRP methodology, those things
don't change as frequently or to quite the same degree. Most
of those other sorts of variables that we use are typically
contained in Utilities' IRPs, which get updated every two
years. But, the Commission does not automatically update those
variables when IRPs are revised or updated unless a filing is
made, so it's not an automatic scheduled update process that
necessarily coincides with updates that are made in the IRPs.
We are reliant upon -- we've been reliant upon the Utilities in
the past to make those sorts of filings to proposed changes
that they think are appropriate.
Q. So do we need to have a different system? Do we
need to have a specified periodic update?
A. Again, I think it is necessary for fuel price,
but I'm not convinced it's absolutely necessary for some of the
other variables.
Q. It also seems, to me, that we have tried to
address some of these questions by convening workshops or
informal processes, hoping the parties would come to agreement
on certain terms. Have we done that?
A. We've made attempts to do that.
Q. And those have been totally unsuccessful, as I
recall?
A. I would agree.
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Q. Because it seems like these issues are so
contentious, the parties are incapable of working out
reasonable solutions on their own?
A. I don't think we would have been here today and
yesterday if we could have reached some collaborative solution
to these issues.
Q. Okay. And, finally, you were asked a question
about grumbling on the part of others, and so I couldn't resist
asking is there anything that's done here at the Public
Utilities Commission that doesn't cause some degree of
grumbling from some group? I just want to know what it is.
A. It sure doesn't seem like there's anything we can
Q. So perhaps we can eliminate grumbling.
COMMISSIONER SMITH: Ms. Sasser, do you have any
redirect?
MS. SASSER: I have just a couple of questions.
They will not take very much time. Thank you, Madam Chair.
REDIRECT EXAMINATION
21
22 BY MS. SASSER:
23
Q. Mr. Sterling, in regard to Mr. Richardson's
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hypothetical about digesters, are most digesters under ten
.
25 megawatt facilities?
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HEDRICK COURT REPORTING STERLING (Di)
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1 A. All of the ones that currently have PURPA
contracts in Idaho are substantially less than ten megawatts.
3 Q. And isn't it Staff's proposal to continue to
4 allow 20-year contracts for ten megawatt and under projects?
5 A. It's Staff's proposal that all projects with
6 rates determined under the SAR method be entitled to 20-year
7 contracts.
Q. So --
A. So for a biomass project, the cap would be ten
megawatts, ten average megawatts, but for wind and solar it
would be 100 kilowatts.
Q. So Mr. Richardson's concern about digesters, as
you've stated with digesters all being below the ten megawatt
threshold, doesn't exist?
A. That's correct.
Q. Thank you. With regard to fuel risk between a
Utility and a QF facility, isn't it true that Company combined
cycle units are economically dispatchable?
A. Yes, that's correct.
Q. They only run when they're in the money?
A. That's correct.
Q. So the Company can avoid high fuel costs by not
running the combined cycle units?
A. Yes, that's true.
Q. And isn't it true that fuel costs for QF
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contracts are locked in and cannot be avoided if better prices
are available in the market?
A. That's also true.
Q. Thank you. To touch on some of the cross of
Mr. Arkoosh and some of Mr. Richardson regarding existing
contracts and the application of 18 CFR 292.304(f), did you
review existing contracts in preparing for this hearing?
A. Yes, I did.
Q. Back to what year?
A. Well, I traced them back beyond 1985, and I
stopped in 1985 because it was December of 1985 when the
particular contract terms that I was searching for first became
commonly inserted in contracts. So I was looking for the point
in time at which that contract term was routinely inserted in
the contracts, and so it was back to 1985 is what I examined.
Q. And when you refer to "that contract term," Idaho
Wind Partners submitted multiple copies of power purchase
agreements that it has with Idaho Power.
COMMISSIONER SMITH: They submitted one copy each
of multiple agreements.
MS. SASSER: Thank you for the clarification.
Q. BY MS. SASSER: So if you were to look at any one
of those exhibits -- I can give it to you if you need it, but
I'm looking at Exhibit 2102 -- the terms that were discussed
with Mr. Guy, the clause in that contract, 7.5, where it talks
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about continuing jurisdiction of the Commission and states
"This Agreement is a special contract and, as such, the rates,
terms and conditions contained in this Agreement will be
construed in accordance with 18 CFR Section 292.303 through
308," in your review of the contracts back to 1985, is that a
clause that is included in all of those contracts across
Utilities?
A. It's been a standard paragraph in every Idaho
Power contract, including all of Idaho Wind's contracts, since
December of 1985.
Q. Thank you. One last question, and it's to
clarify Commissioner Smith's questions about vigilance and part
of what happened in Idaho and how it got out of hand:
Aren't federal tax credits for renewable projects
a large part of what caused the uncontrolled QF development in
Idaho?
COMMISSIONER SMITH: I hope you're not
characterizing my question as using the words "out of hand" and
"uncontrollable." I did not use those words.
MS. SASSER: I can rephrase if you want me to.
Q. BY MS. SASSER: Are federal tax credits part of
the cause of the situation that we find ourself in today?
A. Yes, it's certainly been a factor. It has
made -- it's one reason, among others, but it's one reason why
we've seen a proliferation of particularly wind projects in the
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last roughly five years.
Q. That's all I have. Thank you.
MS. SASSER: Thank you, Madam Chair.
COMMISSIONER SMITH: Thank you, Ms. Sasser.
Well, we've conveniently arrived at five o'clock.
According to my list, we have two more witnesses to hear from,
Mr. Sorenson and Mr. Hansten, which I'm told Mr. Sorenson will
be here at 9:00 a.m. in the morning, and the same for
Mr. Hansten.
MR. ARKOOSH: Madam Chairman, Mr. Hansten filed
about four pages of testimony and did not differ -- actually,
it wasn't even as extensive as Mr. Zamora's. It's the same.
Does somebody want him up here for cross-examination I guess is
the question.
COMMISSIONER SMITH: So let us poll the parties.
MR. R. WILLIAMS: Madam Chair, I would make the
same request with Mr. Sorenson. He's prepared to driver over
from Idaho Falls tomorrow morning and be on cross-examination,
but to subject him to eight hours of driving for no one to have
any questions I think -- so I would make the same request. If
anybody has any questions for him, he will be here.
COMMISSIONER SMITH: So, let's go off the record
for a few minutes, Wendy.
(Discussion off the record.)
COMMISSIONER SMITH: Let's go back on the record.
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At this point in time, we will spread the
prefiled testimony of Mr. Ted Sorenson and Mr. Alan Hansten
upon the record as if it had been read, noting there are no
objections by any party to this proceeding about their
testimony being in the record without them actually appearing
here to be cross-examined.
(The following prefiled direct testimony
of Mr. Ted Sorenson and Mr. Alan Hansten is spread upon the
record.)
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I 1204 I
FIEDRICK COURT REPORTING COLLOQUY
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I Q. Please state your name and business address.

2 A. My name is Ted Sorenson P E and my business address is 5203 S. 11th

3 East, Idaho Falls, Idaho.

4 Q. By whom are you employed and in what capacity?

5 A. I am employed by and am the owner of Sorenson Engineering.

6 Q. What is your educational background?

7 A. I received a Bachelor of Science in Civil Engineering, December 1974,
8 from the University of Idaho and a Masters in Civil Engineering, May 1976, also from
9 the University of Idaho.

10 Q. Please describe your professional and work experience.

11 A. I am a registered professional engineer in in the states of Idaho, Oregon,
12 Montana and Colorado. Attached as Exhibit No. 801 is a summary list of the
13 hydroelectric projects I have completed in my career. I have ownership in 5 hydro
14 projects in Idaho, and in other projects in other states and countries. I am also a member
15 of the Renewable Energy Coalition.

16 Q. What is the purpose of your testimony in this proceeding?

17 A. The purpose of my testimony is to respond to some of the proposals of
18 Idaho Power Company, Rocky Mountain Power, and Avista Utilities as they relate to
19 small Q F projects, and more specifically, small canal and run-of-river hydro projects.

20 Q. Should the Commission continue distinctions between certain types and/or
21 sizes of PURPA projects?

22 A. Yes. First, the Commission needs to recognize differences between larger
23 and smaller PURPA projects, and also between certain types of PURPA projects. This
24 includes the importance of recognizing the difference in needs and significance of
25 existing hydroelectric projects versus proposed iWJojects. For example, I believe the
SORENSON, Di 1
Renewable Energy Coalition

I standard rate eligibility cap for resources that cannot be disaggregated should be
2 reinstated to ten megawatts, nameplate capacity. There should remain in place a
3 threshold for access to a simpler, more efficient contracting system, for projects that do
4 not have the ability to easily multiple one project into several. Because of the unique

5 physical characteristics and location of small-scale hydroelectric facilities in Idaho,
6 developers of hydro projects smaller than 10 MW should continue to have access to
7 standard, published QF rates. They also need a more streamlined and transparent
8 contracting process which would include a standard form power purchase agreement
9 (PPA) for both existing and new projects, reasonable pre-conditions and certainty and/or
10 predictability to changes in avoided cost prices.

11 Q. Why is this cap distinguishing certain types or sizes of QFs important?

12 A. Contrary to what is said or implied in some of the utility testimony, many

13 small hydro developers do not have the sophistication and financial resources to
14 separately negotiate individual PPAs, especially when avoided cost prices can change
15 quickly or often. While the consulting and legal expertise needed to calculate individual
16 IRP rates and negotiate a PPA can always be retained, the reality is that outside legal and
17 consulting fees can quickly make a small hydro project uneconomic. Nor does a small
18 hydro developer such as myself have the benefit of spreading the costs of negotiating one
19 PPA over three, four of five additional mirror-image projects.

20 Q. What other recommendations do you have for small projects below the

21 eligibility cap?

22 A. I endorse the recommendations of Mr. Don Schoenbeck, the expert
23 witness for REC, the Twin Falls Canal Company and the North Side Canal company,

• 24 related to standard rates, procedures and the time frames for changes in avoided cost
25 rates, for projects below a 10 MW eligibility capi 206
SORENSON, Di 2
Renewable Energy Coalition

I Q. Idaho Power also proposes that QF contracts be limited to five years.
0 2 What is your opinion of this recommendation?

3 A. It is a punitive proposal that seems primarily designed to wreck the QF
4 industry, or at least would kill the small hydro QF industry. It would be virtually
5 impossible to finance the building of a new hydro project based on the revenue stream of
6 a five year contract. Hydro QFs, by their very nature, are extremely capital intensive and
7 need longer-term contracts in order to debt finance the capital costs necessary for a new
8 dam, turbines and other equipment. Idaho Power knows and understands this; it is a
9 hydro rich utility and its ratepayers benefit from this legacy of large, long-term capital
10 investments in similar assets. Once operating, hydro generation has virtually no fuel cost.

11 Q. How does Idaho Power's 5 year contract length also impact existing QF
12 hydro projects?

13 A. Many existing projects with PPAs starting to expire could be at risk of
14 continued operation. In essence, some of these legacy hydro QFs on the Idaho Power or
15 PacifiCorp system might have to shut down, if only 5 year contracts were available. Dam
16 repairs, equipment upgrades including interconnection, installation of better or more
17 efficient environmental protection, and re-newed governmental permits are many times
18 required at the end of a PPA. Without an adequate long-term PPA, these essential and
19 often required repairs and improvements could not be financed. It is disingenuous for
20 Idaho Power to expect its ratepayers to commit to paying for similar major capital

21 investments involved in the Shoshone Falls power plant rebuild, but then assert that
22 hydro PURPA projects should not be treated the same, in order to protect customers from
23 market risk. The same risk applies to both types of projects, and the same benefits of
24 preserving and extending the life of the hydro system applies equally to both QF hydros
25 and utility owned hydros. I must also point out IQVAvista and Rocky Mountain do not
SORENSON, Di 3
Renewable Energy Coalition

1 appear to believe that 20 year QF contracts are a problem.

2 Q. Do you have a recommendation regarding standardization of avoided costs

3 for smaller projects?

4 A. Yes. I agree with Rocky Mountain Power witness Brown where she
5 recommends a standardization of avoided cost rates for non-wind and non-solar QFs
6 below an eligibility cap threshold, because it provides a simple and transparent means of
7 pricing that minimizes transaction costs.

8 Q. What about standard contracts and procedures?

9 A. I believe there are also elements of Rocky Mountain Power witness
10 Clements' testimony, with respect to larger projects, that would have value for both the

11 utility and the QF, for projects below the eligibility cap. For example, and without
12 endorsing specific components of Mr. Clements' proposed Schedule 38, the concept of a
13 list of requirements and schedule of actions and responses, would provide transparency,
14 simplicity and certainty to QFs below a 10 MW cap. The major addition I believe is
15 necessary for small projects would be to also develop standardized contracts. These are
16 similar to requirements which Idaho Power and PacifiCorp must meet in other states and
17 to a great extent already exist.

18 Q. Idaho Power proposes a new Schedule 74 which would allow the company
19 to interrupt deliveries from QFs during periods of low load, and instead run its own base
20 load generation, which it classifies as "must run." The Company classifies its run of river

21 hydro plants as "must run," stating that it cannot back these units down. (Parks, at
22 page 24).

23 Q. Do you agree that run-of-river hydro units should be classified as must
24 run?

25 A. No. From a physical or operation1tndpoint, hydro units are very
SORENSON, Di 4
Renewable Energy Coalition
I flexible in when and how much electricity they generate.
1* 2 Q. Without getting into a discussion of legal issues concerning what Idaho
3 Power's FERC licenses may or may not require, is it physically possible to ramp hydro
4 generation, up or down?

5 A. Yes. For run-of—river hydro projects it is almost always physically
6 possible to back down or curtail hydroelectric generation without impacting downstream
7 flows. This can happen in several ways. If a hydro project is using a Pelton Turbine,
8 water can still pass through the turbine, without the turbine actually generating electricity.
9 For other types of turbines, such as Frances or Kaplan, direct water pass-through does not
10 work and water would be diverted to pass around the turbine and be "spilled" into the

11 river below.

12 Q. Can you provide an example?

13 A. Yes, a good example would be Idaho Power's Shoshone Falls hydro plant.
14 If Idaho Power wished to curtail generation at this plant, it would simply divert water
15 away from the plant's penstock leading down to plant, allowing the water to instead go
16 over Shoshone Falls and into the river below the generating facility.

17 Q. Once curtailed, could generation at Shoshone Falls then be quickly
18 brought back on line?

19 A. Yes. The turbine wicket gates would be opened, the water would again
20 flow to the generators and the Shoshone Falls plant would be back on line, in a relatively

21 short period of time.

22 Q. Rocky Mountain Power recommends that environmental attributes (EAs)
23 generated by a QF project, including renewable energy credits (RECs), should go to the
24 utility, along with the QF energy sold to the utility. Do you agree?

25 A. I think it should depend on the t=O resource identified by the utility in
SORENSON, Di 5
Renewable Energy Coalition

I its IRP as the next major identifiable avoided generating asset. If that avoidable resource
0 2 is a renewable resource, then the EAs and RECs from the QF renewable resource should

3 go to the utility as part of the power sale. After all, the QF resource in this instance is
4 deferring the utility owned renewable resource, and it makes sense that the utility should
5 also get the EAs and RECs as part of the power purchase.

6 On the other hand, if the next IRP identified avoidable resource of a utility
7 that is used to set the standard avoided cost is not a renewable resource - for instance, a
8 gas fired power plant - the EAs and RECs from a renewable QF sale should not also
9 transfer to the utility along with the sale of power, without additional compensation. For
10 Idaho Power and PacifiCorp, the next avoidable generating units appear to be gas fired
11 power plants. In the case of these two utilities, the EAs and RECs for renewable QF
12 projects selling power to them should remain with the developer and the standard
9 13 contracts developed for projects below the 10 MW eligibility cap should contain a clear

14 statement to that effect.

15 Q. Does this conclude your testimony?

16 A. Yes
1210
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SORENSON, Di 6
Renewable Energy Coalition
I Q. PLEASE STATE YOUR NAME.
2 A. Alan Wayne Hansten
3 Q. WHAT IS YOUR BUSINESS ADDRESS?
4 A. North Side Canal Company, Ltd., 921 N. Lincoln, Jerome, Idaho.
5 Q. HOW ARE YOU EMPLOYED?
6 A. I am the Assistant Manager of North Side Canal Company ("NSCC").
7 Q. WHAT IS YOUR EDUCATIONAL BACKGROUND?
8 A. I attended the College of Southern Idaho from 1988 to 1990. In 1990 I
9 transferred to the University of Idaho. I received my Bachelor of Science Degree
10 in 1993 and my Master of Science Degree in 1995, both in Agricultural
11 Engineering. In 1998 I received my Professional Engineer's license in Civil
12 Engineering in Idaho and presently also hold an inactive license in Nevada.
13 Q. WHAT IS YOUR WORK EXPERIENCE?
14 A. After receiving my Bachelor's Degree in the spring of 1993 I worked for three
15 months with the Idaho Department of Water Resources in the Twin Falls office
16 performing water right field exams. In the fall of 1993 I went to work for EHM
17 Engineers, Inc. in Twin Falls, initially as a surveyor and then as a design
18 engineer. In 2000 I went to work for JUB Engineers, Inc. as an engineering
19 project manager where I oversaw the design and construction engineering
20 services for projects including commercial building sites, residential
21 subdivisions, airport improvements, water systems, sewage collection systems,
22 irrigation systems and highway improvements. In 2004 I went to work for
23 Riedesel Engineering, Inc. as a project engineering manager working primarily
S Case No. GNR-E-1 1-03 Hansten, Di
May 2, 2012 1211 Twin Falls Canal Company
North Side Canal Company
Page 1 of 3
I on airport improvement projects, commercial sites, residential subdivisions and
is 2 highway projects.
3 In 2008 I accepted the Assistant Manager position at NSCC, and I began
4 work there in February of 2009.
5 Q. PLEASE DESCRIBE YOUR DUTIES IN YOUR PRESENT
6 EMPLOYMENT.
7 A. My duties for the NSCC include public relations; oversight and engineering of
8 canal system improvements; periodic oversight of water delivery operations; new
9 hydroelectric development planning; assisting with issues as they relate to the
10 four existing hydroelectric projects on the North Side Canal system; and keeping
11 informed of legal proceedings and policies that may impact the NSCC and/or the
12 North Side Energy Company ("NSEC"), a wholly-owned subsidiary of NSCC.
13 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY HERE?
14 A. The purpose of my testimony here is to convey my agreement with the testimony
15 of Louis Zamora of Twin Falls Canal Company.
16 Q. PLEASE DESCRIBE YOUR PROJECT.
17 A. NSCC is an Idaho non-profit corporation formed under the Carey Act and owned
18 by individual shareholders who pay annual assessments for the operation,
19 maintenance and management of NSCC. Some of the costs of operating NSCC
20 are offset by income received through power generation. NSCC delivers water to
21 168,000 acres of farm ground through 1,000 miles of canals and laterals.
22 Q. PLEASE DESCRIBE THE PLANTS OWNED BY YOUR PROJECT.
Case No. GNR-E-1 1-03 Hansten, Di
May 2, 2012 1212 Twin Falls Canal Company
North Side Canal Company
Page 2 of 3
I A. NSEC manages four small hydroelectric generation facilities in partnerships with
2 ENEL North America and Ida-West Energy Company.
3 Q. PLEASE CATALOGUE THE FUTURE POTENTIAL ENERGY
4 ASPECTS OF YOUR PROJECT.
5 A. We have performed an abbreviated feasibility study and located eighteen
6 potential sites for power production.
7 Q. ARE YOU FAMILIAR WITH THE TESTIMONY OF LOUIS ZAMORA
8 AND DON SCHOENBECK?
9 A. Yes
10 Q. DO YOU CONCUR WITH AND ADOPT THE POSITIONS CONTAINED
11 WITHIN THAT TESTIMONY?
12 A. Yes.
13 Q. DOES THAT CONCLUDE YOUR TESTIMONY?
14 A. Yes.
. Case No. GNR-E-1 1-03 Hansten, Di
May 2, 2012 1213 Twin Falls Canal Company
North Side Canal Company
Page 3 of 3
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I * 25
(The following proceedings were had in
open hearing.)
(Twin Falls Canal Company, et al, Exhibit
No. 801 was premarked for identification.)
COMMISSIONER SMITH: Furthermore, we'll be
adjourned for this evening and we will convene at 9:00 a.m., in
the morning, for the purposes of allowing parties to make brief
closing statements.
(The hearing adjourned.)
I 1214 I
HEDRICK COURT REPORTING COLLOQUY
P. 0. BOX 578, BOISE, ID 83701