20120503Schoenbeck Direct.pdf

RECEIVED
Ui1IT']
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA QF CONTRACT
PROVISIONS INCLUDING THE
SURROGATE AVOIDED RESOURCES (SAR)
AND INTEGRATED RESOURCE PLANNING
(IRP) METHODOLOGIES FOR
CALCULATING PUBLISHED AVOIDED
COST RATES
Case No. GNR-E-11-03
DIRECT TESTIMONY OF
DONALD W. SCHOENBECK
ON BEHALF OF
NORTHSIDE CANAL COMPANY
TWIN FALLS CANAL COMPANY
RENEWABLE ENERGY COALITION
CASE NO. GNR-E-11-03
DIRECT TESTIMONY OF
DONALD W. SCHOENBECK
CONTENTS
I.INTRODUCTION AND SUMMARY ...................................................................... 1
II.ELIGIBILITY CAP AND CONTRACT TERM.......................................................3
III.AVOIDED COST PRICING.....................................................................................14
IV.OTHER IDAHO POWER TERMS AND CONDITIONS........................................35
V.AVISTA AND PACIFICORP CONTRACTING MATTERS..................................42
Donald W. Schoenbeck Page i of i

1 PREFILED DIRECT TESTIMONY OF

2 DONALD W. SCHOENBECK

3 I. INTRODUCTION AND SUMMARY
4 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

I A. My name is Donald W. Schoenbeck. I am a member of Regulatory &

6 Cogeneration Services, Inc. ("RCS"), a utility rate and economic consulting firm.

7 My business address is 900 Washington Street, Suite 780, Vancouver, WA 98660.
8 I Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE.

9 A. I've been involved in the electric and gas utility industries for over 40 years. For

10 the majority of this time, I have provided consulting services for large industrial

11 customers addressing regulatory and contractual matters. A significant portion of

12 my work has included testifying on avoided cost pricing and the negotiation of

13 contracts for Qualifying Facilities ("QFs"). A further description of my

14 educational background and work experience can be found in Exhibit No. 1101

15 filed with this testimony.
16 Q. ON WHOSE BEHALF ARE YOU SUBMITTING THIS TESTIMONY?

17 A. This testimony is on behalf of Northside Canal Company, Twin Falls Canal

18 Company and Renewable Energy Coalition (collectively, "QF Companies").
19 Q. WHAT TOPICS WILL YOUR TESTIMONY ADDRESS?

20 A. I will discuss various aspects of the utility proposals to modify the manner in

21 which avoided cost prices are determined pursuant to the Public Utilities
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 1 of 45

1 Regulatory Policies Act of 1978 ("PURPA") as implemented by the Idaho Public

2 Utilities Commission ("Commission") and certain power purchase agreement

3 ("PPA") provisions. While most of my testimony will address the testimony filed

4 on behalf of the Idaho Power Company ("Idaho Power"), my recommendations

5 should apply to Avista Corporation ("Avista") and PacifiCorp/dba Rocky

6 Mountain Power ("PacifiCorp") as well.
7 Q. PLEASE BRIEFLY SUMMARIZE YOUR FINDINGS AND

8 RECOMMENDATIONS ADDRESSED IN THIS TESTIMONY.
9 A. On behalf of the QF Companies I recommend the following:

10 Establish an eligibility cap of ten megawatts (10 MW) of nameplate

11 capacity for published avoided cost prices.

12 Maintain a maximum contract term of twenty (20) years for published

13 fixed prices under PPAs for QFs at or below the eligibility cap.

14 Allow all avoided energy costs to be determined using a third party

15 production simulation model such as AURORA ,f

16 Two computer simulations are performed ("QF-

17 inIQF-out")and there are no "post processing"

18 adjustments such as proposed by Idaho Power.
19

20 Between integrated resource plan periods the only

21 avoided energy cost updates can be for gas price

22 changes (once per year and from a third party

23 source) and additional executed QF PPAs.
24

25 Carbon costs are included in the avoided cost

26 energy simulations.
27

28 All environmental attributes (such as renewable

29 energy certificates) are retained by the seller.

30 Avoided capacity costs should be determined based upon the particular

31 needs of each utility. At this time, a single cycle combustion turbine
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Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 2 of 45
("SCCT") should be used to derive capacity prices for just Idaho Power
while a combined cycle combustion turbine ("CCCT") would be used to
derive PacifiCorp' s avoided capacity prices.
In calculating avoided capacity prices for a new QF, no capacity value
should be included for periods when a utility has excess capacity based on
a one day in ten year loss of load analysis. However, the PPA capacity
price should be paid over each and every year of the PPA.
Full capacity value should be included and paid in each and every year to
a QF with a follow-on PPA.
10 The PPA capacity prices should only be paid during the peak months and
11 on-peak hours of each utility.
12
13 The Commission should order that workshops be held at the conclusion of
14 this phase of this proceeding to develop a standard tariff for PPA
15 negotiations and standard PPAs for each utility.
16
17 If non-pricing contractual issues are to be addressed and decided now, the
18 Commission should order that the QFs with standard PPAs: (i) will not be
19 subject to operational curtailment (i.e., reject Idaho Power's proposed
20 Schedule 74), (ii) can be executed up to five years prior to commercial
21 operation with "locked-in" fixed pricing, and (iii) contain liquidated
22 damage provision options including both a fixed dollars per kilowatt price
23 and a mark-to-market method.
24
25 II. ELIGIBILITY CAP AND CONTRACT TERM
26 Q. PLEASE EXPLAIN THE IMPORTANCE OF THE ELIGIBILITY CAP
27 WITH REGARD TO AVOIDED COST PRICING IN IDAHO.
28 A. The megawatt cap determines if a QF is eligible for standard published prices as
29 compared to having to negotiate prices with the utility. If the QF facility is less
30 than the eligibility cap, the QF can avail itself of published avoided cost rates
31 based on a surrogate avoided resource ("SAR") methodology. The current
32 surrogate avoided resource for all three utilities is a CCCT. If the QF facility is
33 larger than the eligibility cap, the QF avoided cost prices are determined under
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 3 of 45

1 what is termed the integrated resource plan ("IRP") methodology. Under the IRP

2 method, avoided energy costs are determined by performing two production cost

3 computer simulations. The first computer simulation derives the company's

4 production costs over the planning horizon under a base case set of assumptions

5 consistent with the utility's integrated resource plan and the second simulation

6 determines the production costs with the QF included in the utility's resource mix.

7 The difference in costs between these "QF-inIQF-out" simulations is used in

8 deriving the avoided energy costs paid to the QF. As capacity costs are not

9 included in the production simulations, the fixed costs associated with a surrogate

10 resource are used—currently a CCCT—for deriving the avoided capacity costs
paid to the QF. Finally, for intermittent resources such as solar and wind, there is
an integration adjustment to the prices paid to the QF.
13 Q. WHAT HAS THE ELIGIBILITY CAP BEEN IN IDAHO?

14 I A. Until Order No. 32176, the cap had been 10 MW since July 2002 for all QF types.

15 This cap figure was originally applied as being 10 MW of capacity but in

16 November 2004, the cap was clarified to be 10 average megawatts ("aMW") in

17 any month. (Order No. 29632, page 14). With the issuance of Order 32176, the

18 Commission reduced the cap from 10 aMW to 100 kilowatts ("kW") for wind and

19 solar QFs, effective December 14, 2010, while maintaining the cap at 10 aMW for

20 all other technologies. With the issuance of Order No. 32498 on March 22, 2012,

21 the Commission directed that all contracts executed by Idaho Power in excess for

22 100 kW must be presented to the Commission for approval until such time that

23 the Commission modifies this determination.
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 Q. WHAT IS IDAHO POWER'S PROPOSAL IN THIS PROCEEDING FOR
2 AN ELIGIBILITY CAP VALUE?
3 A. Idaho Power is proposing that the cap be set at 100 kW for all QF technologies.
4 Q. WHAT IS THE MAXIMUM TERM FOR WHICH IDAHO POWER IS

5 WILLING TO OFFER FIXED PRICE CONTRACTS TO QFS?
6, A. Idaho Power is proposing that fixed-price contracts be limited to a maximum term

7 of only five years. This is a substantial reduction from the existing authorized

8 maximum term of 20 years.
9 Q. WHY IS IDAHO POWER PROPOSING SUCH RADICAL CHANGES TO

10 THE ELIGIBILITY CAP SIZE AND CONTRACT TERM?

11 A. It would appear that most of Idaho Power's testimony on these matters has to do

12 with a concern or fear that the avoided costs prices will not be properly

13 established when the contracts are executed or the contract prices may not be

14 correct based on an after-the-fact analysis. Other than these concerns, which I

15 will address later in this testimony, Idaho Power has offered little else in support

16 of these two very substantial and adverse changes.

17 With regard to the extremely low cap value, Idaho Power argues having

18 fixed prices in place for as long as two years could expose customers to high

19 avoided cost payments due to "unforeseen circumstances or risks". It asserts

20 these conditions could be taken into account in negotiating a contract with an

21 updated IRP method determination. Regarding the five year maximum contract

22 term, Idaho Power asserts that "locking in" fixed prices "shifts market price risk
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 from the project developer/owner entirely onto Idaho Power's customers". (See

2 Stokes 43-46).
3 Q. DO YOU AGREE WITH IDAHO POWER'S PROPOSAL WITH REGARD

4 TO ELIGIBILITY SIZE AND CONTRACT TERM?

5 A. No. The proposed eligibility size is far too small and contract term is far too

6 short. At a cap level of just 100 kW, virtually every QF contract would be a non-

7 standard PPA requiring the QF to negotiate the prices, terms and conditions of the

8 agreement. State commissions have discretion under PURPA to determine the

9 level of QF capacity that is eligible for standard rates above 100 kW. For most of

10 the years since PURPA was enacted, this Commission has had in place a 10 MW

11 cap (From 1997 to 2002, the eligibility cap was 1 MW or 5 MW). In 2005, the

12 Oregon commission ordered an eligibility cap of 10 MW that is still in effect

13 today. More recently, in December 2010, as part of the settlement on avoided

14 cost matters the California commission approved an eligibility cap of 20 MW.
15 Q. WHY HAVE COMMISSIONS APPROVED ELIGIBLITY CAPS IN THE

16 10 TO 20 MW RANGE?

17 A. I believe there are several significant reasons which have to do with transaction

18 costs, economies of scale, lack of alternative markets and FERC's regulations for

19 implementing PURPA in response to the Energy Policy Act of 2005 ("EP Act

20 2005").

21 Forcing virtually every QF to negotiate a non-standard contract adds to the

22 upfront transactional costs by extending the period over which the QF could

23 ascertain if the project was commercially viable based upon a complete review of
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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the prices, terms and conditions offered by the utility. In addition, it would only

2 be prudent for the QF to retain the necessary expertise to assist in the evaluation

3 and negotiation of the contract. It has been my experience that negotiating a non-

4 standard QF PPA with a utility can take a great deal of time. In some instances,

5 the slowness in which a utility will negotiate a PPA can cause a project to not be

6 built as the developer may not have the time or money for an extended negotiation

7 process. These additional transactional costs could well make a smaller project

8 uneconomical.

9 Setting a low cap may also impact project viability due the economies of

10 scale that are inherent in the utility industry. Typically, utility-owned resources

11 benefit from being sized large enough such that the dollar-per-kilowatt investment

12 required to build the plant is less than for a much smaller sized QF of the same

13 basic technology. Establishing a reasonable size cap, in the 10 to 20 MW range

14 will allow some scaling benefits for the QF.

15 The typical short-term power sale trades in the Pacific Northwest

16 electricity market are for blocks of 25 MW for each and every hour of the "on-

17 peak" period, Monday through Saturday, 6:00 a.m. to 10 p.m., or "off-peak

18 period",all other hours plus holidays. Only in California is there an organized

19 market run by an independent administrator, California Independent System

20 Operator ("CAISO"), for day-ahead or real-time products in the Western United

21 States. Consequently, QFs in the Pacific Northwest cannot provide the product
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 most traded nor do they have access to competitive organized markets for their

2 products.

3 Finally, the EP Act 2005 established a new section within PURPA that

4 relieves a utility of the obligation to purchase QF power if the utility has sought

5 and received a waiver of the obligation from FERC by showing the QF has

6 wholesale market access under certain standards. However, in implementing EP

7 Act 2005, FERC ruled that even where QFs have market access, the utility is

8 only relieved of the must purchase obligation for QFs larger than 20 MW. In
9 ' other words, utilities must still purchase QF power from "smaller" facilities if the

10 facility is less than 20 MW. All these factors suggest an eligibility cap much

11 greater than Idaho Power's 100 kW value.

12 Idaho Power has not addressed the reasons why state commissions have

13 imposed much greater values in recognition of the hurdles facing the development

14 of smaller QF facilities. Idaho Power's reasoning for proposing a cap of 100 kW,

15 so it can apply the latest available information as part of the IRP method,is really

16 a pricing issue. This can be more appropriately addressed by modifying the

17 manner in which the fixed prices are determined.
18 Q. WHY DO YOU DISAGREE WITH A CONTRACT TERM OF JUST FIVE

19 YEARS?

20 A. There are three reasons: fairness, equity and insufficient cost recovery period.
21 Q. WHAT IS UNFAIR ABOUT THE COMPANY'S PROPOSED FIVE YEAR

22 TERM?
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 8 of 45

1 A. The five-year term is unfair and inappropriate because it creates such a mismatch

2 between the maximum contract term allowed a QF versus the economic life used

3 or assumed for a comparable utility-owned resource. In Idaho Power's 2011

4 Integrated Resource Plan, a thirty (30) year plant life is used for all the resource

5 types illustrated in Idaho Power's Exhibit No. 8. As deliveries from QFs are in

6 part in lieu of building company-owned resources, a contract life comparable to

7 the utility-owned resource life is only fair and equitable. I am sure Idaho Power

8 would be unwilling to invest in a resource if it was only assured of some cost

9 recovery for just five years and had no assurance of a follow-on contract at the

10 end of this five year period.
11 Q. WHY ARE YOU EMPHASIZING THE WORD "SOME" COST

12 RECOVERY?

13 A. As I will explain later in this testimony, Idaho Power's avoided capacity pricing

14 proposal will only include a capacity value in the avoided cost contract prices if

15 there is a need for capacity. As such, the capacity provided by any QF under a

16 five-year extension agreement or a follow-on PPA could well be bumped or

17 displaced by any utility-owned or contracted-for resource that has been executed

18 subsequent to the initial QF PPA. For resources such as those owned by the QF

19 companies that have been providing reliable capacity for a number of years, the

20 Idaho Power proposal is patently inequitable.
21 Q. WHY WON'T A FIVE-YEAR TERM ALLOW FOR REASONABLE COST

22 RECOVERY?
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 9 of 45
1 A. A contract term of just five years is simply an insufficient time period to provide
2 any prospect for the recovery of the investment in the facility in today's markets.
3 For all but the spring period, the California market tends to dominate western
4 market prices due to its resource mix. Every year in its annual market report, the
CAISO publishes the results of an analysis it conducts to see if a new market
6 entrant would generate sufficient market revenue to cover its costs. For the last
7' several years, this analysis has shown that the net market revenue (total market
8 revenue less variable operating costs) generated from sales in the CAISO markets
9; are inadequate to allow a new combined cycle facility to recover its fixed costs as
10 shown by the following table.
11
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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I
CAISO Annual Fixed Cost versus Net Market
Revenue in Excess of Variable Costs
($/kW-year)
NP15 Net SP15 Net
CCCT Fixed Market Market
Year Cost Revenue Revenue
2009 $190.70 $40.14 $38.48
2010 $190.70 $30.60 $35.52
2011 $190.70 $23.30 $22.99
2

3 From this analysis, the CAISO appropriately concluded:

4 These findings continue to underscore the critical

5 importance of long term contracting as the primary

6 means for facilitating new generation investment.

7 Local requirements for new generation investment

8 should be addressed through long-term bilateral

9 contracting under the CPUC resource adequacy

10 and long-term procurement framework (CAISO

11 Annual Report on Market Issues and Performance,

12 April 2012, page 47)
13

14 A similar type of analysis and result can be done using Idaho Power's

15 estimated capital costs and projected avoided cost payments under its pricing

16 proposals in this proceeding. The following table compares the estimated capital

17' cost of select resources with the revenue recovery under Idaho Power's proposed

18 five-year maximum contract term and proposed QF prices. The capital cost

19 estimates (dollars per kilowatt-"$/kW") were taken directly from Idaho Power's

20 2011 Integrated Resource Plan ("2011 Plan") Appendix C, page 82. The values

21 in the other columns represent 100% of the revenue received over five years using

22 the monthly avoided cost prices Idaho Power provided in response to Staff
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
Production Request No. 15 along with the estimated monthly deliveries for each
resource type used in compiling Idaho Power's Exhibit No. 8. The revenue value
was converted to the $/kW value shown in the table using the associated capacity
of each resource. The column in the table labeled "Revenue Recovery 2013-
2017" uses the prices of both capacity and energy, from every month of the Idaho
Power data response times the associated monthly energy to calculate the total
expected revenue for a five-year period for each resource type. The column
labeled "2017 Revenue Recovery for 5 Years" is a five-year revenue amount
based solely on the 2017 revenue (2017 revenue multiplied by 5 years). This
single year was chosen as the monthly avoided cost prices include full capacity
value for the entire year.
Capital Cost versus Revenue Recovery for a 5 Year Period
($/kW)
Idaho Revenue 2017
Power IRP Recovery Revenue
Capital Years Recovery for
Resource Type Cost 2013-2017 5 Years
Baseload
(Geothermal) $6,250 $1,573 $2,003
Hydro/Canal Drop $4,000 $665 $960
Wind $1,450 $426 $474
Solar $2,115 $377 $554
It is important to emphasize that the revenue recovery values in the table have not
been reduced to reflect any annual costs that would be incurred by the facility
such as operations and maintenance expense for running the facility, property
taxes or insurance. Even based upon the 2017 prices, with full capacity payments
Case No. GNR-E-1 1-03
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 each and every year, a condition that may never materialize under Idaho Power's

2 "sufficiency proposal", Idaho Power's maximum contract term of just five years

3 is woefully inadequate for the QF to recover its capital investment. In my view,

4 the above table demonstrates the unreasonableness of Idaho Power's proposals in
5' this proceeding. It could well eliminate the development of QF facilities in this

6 state if the Commission were to adopt the proposals.
7 Q. WHAT IS YOUR RESPONSE TO IDAHO POWER'S ASSERTION THAT

8 LOCKING IN A LONGER TERM SHIFTS RISK TO RATE PAYERS?
9 A. The implication of Idaho Power's testimony is that Idaho Power customers will

10 be harmed from locking in fixed prices for a long period of time. This, of course,

11 may not necessarily be the case. In this current period of low gas prices, locking

12 into longer term contracts may in fact provide a substantial benefit if gas prices

13 were to rise above current projections. In actuality, locking into fixed price

14 arrangements reduces Idaho Power's exposure to market price movements. More

15 importantly, however, the Idaho Power witnesses really appear to be arguing that

16 a different standard of prudency and reasonableness should be used for judging

17 QF contracts as compared to utility owned resources. For QF resources, Idaho

18 Power seems to imply there should be an ongoing review as to the

19 appropriateness of the QF payments. However, for utility-owned resources or

20 inter-utility PPAs, Idaho Power, like all other utilities, will argue just one

21 reasonableness review should be conducted based on the standard of what was

22 known at the time the decision to acquire the resource or execute the PPA was
Case No. GNR-E-1 1-03
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Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 made. This approach is consistent with the PURPA standards. FERC's

2 regulations provide QFs the right to receive energy and capacity payments based

3 on a forecast of "the avoided costs calculated at the time the obligation is

4 incurred." 18 CFR Section 292.304 (d)(2)(ii). This should be the exact same

5 standard for judging the reasonableness of QF contracts employed by this

6 Commission.
7 Q. WHAT ARE YOUR RECOMMENDATIONS WITH REGARD TO THE

8 ELIGIBILITY CAP AND MAXIMUM CONTRACT TERM IN THIS

9 PROCEEDING?

10 A. For all the reasons I have presented in this testimony, I recommend the eligibility

11 cap be set at the low end of a reasonable range, that being 10 MW of nameplate

12 capacity for all technologies, along with a maximum contract term of 20 years.

13 These values will reduce the administrative costs on Idaho Power and the

14 Commission in having to carefully review and approve virtually every single QF

15 contract under Idaho Power's proposal. It will also lower the contracting costs for

16 the QF. The longer contract term will also provide a realistic time frame for a QF

17 to recover its development costs, including its debt financing costs. The

18 reasonableness of these specific recommendations should be considered in total,

19 including the avoided cost pricing methodology I recommend for deriving the

20 published fixed prices.

21 III. AVOIDED COST PRICING
22 Q. DO YOU BELIEVE AVOIDED COSTS CAN BE PROPERLY

23 ESTABLISHED USING EITHER A SAR OR IRP METHOD?
Case No. GNR-E- 11-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 A. Yes. As long as consistent assumptions are used in both methods (such as fuel

2 costs and market price forecasts), all the same costs categories are included in
3 .. both methods and the expected QF generation pattern is taken into account, I

4 believe employing either method would essentially result in similar avoided cost

5 streams. There are trade-offs between using either one of the two methods. A

6 surrogate resource method is generally easier to explain, implement and

7 understand the resulting prices because the calculus is more straightforward and

8 transparent. The surrogate resource calculations can be done using Microsoft's

9 Excel spreadsheet software which most QF owners or developers would already

10 have on their computers. On the other hand, an integrated resource plan method

11 will generally rely on a much more complex "black box" production simulation

12 model that uses thousands of inputs and forecast assumptions in order to derive

13 the avoided cost prices. While most QF owners or developers are likely to

14 understand the workings of an Excel spreadsheet, it is highly unlikely that they

15 are knowledgeable with respect to all the inputs required in a production

16 simulation model such as AURORA and the impact the representation of a

17 particular resource could have on the simulation result. Further, the licensing of a

18 third party production model can be very expensive adding to the QF's transaction

19 cost. For example, the AURORA annual licensing fees range from $39,500 to

20 $150,000 for the basic regional modeling capability. While the integrated

21 resource method may not be as transparent as the surrogate resource method, it

22 can do a better job of taking into account a utility's needs by incorporating all the
Case No. GNR-E-1 1-03
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 expected loads and resources over the contracting planning horizon. This gives

2 the appearance of a more precisely determined, and therefore more accurate,
3! avoided cost prices but the result is driven by all the numerous forecast

4 assumptions and resource representations, many of which will likely be wrong

5 based on a "20-20" hindsight review. For these reasons, in my view either

6 method can be used to determine reasonable avoided cost prices.
7 Q. WHY IS IDAHO POWER PROPOSING TO DISCONTINUE USING THE

8 SAR PRICING METHOD FOR ALL QF CONTRACTS?
9 A. Idaho Power provides four reasons: 1) the use of a high SAR capacity factor does

10 not recognize the economic dispatch that is likely to occur with the resource, 2)

11 the SAR method does not value energy at the time it is delivered or valued by the

12 utility, 3) the SAR method does not recognize the characteristics of different QF

13 resource types, and 4) the SAR method is too static. (See Stokes 40-41).
14 Q. ARE IDAHO POWER'S CRITICISMS VALID?

15 A. Not really, in that every one of these criticisms can be addressed by modifying the

16 manner in which the SAR method is implemented. It does not necessarily follow

17 that the method itself should be abandoned; it could simply be modified. For

18 example, the SAR method could employ an exogenously determined market

19 price, either hourly or monthly by on and off peak period, to incorporate

20 economic displacement of the resource. The resulting energy costs would then

21 reflect the lower of the operating cost of the surrogate resource or the market

22 value. This resulting hourly cost stream would inherently reflect the value of
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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F energy by time period, thereby addressing the Company's second concern.

2 Determining four different sets of published prices based on the four different QF

3 delivery patterns applied to the cost stream would recognize the delivery

4 characteristics of each resource type just as Idaho Power is proposing under their

5 IRP method. Finally, the most critical component or input under a gas-fired

6 surrogate resource method or computer-generated production simulation results of

7 an integrated resource method is the gas price(s) used in the analysis. By requiring

8 annual updates to the gas prices and the corresponding market prices, the SAR

9 method will not be static between integrated resource plan publications.

10 The only item that cannot be directly addressed by these modifications is

11 how additional QFs that commence delivering generation to Idaho Power might

12 impact Idaho's published avoided costs, if at all. To the extent Idaho Power

13 believes it will have requests for numerous additional QF PPAs seeking published

14 fixed prices, the much more costly and work intensive IRP method could be

15 considered to establish all avoided cost prices for both standard and non-standard

16 contracts if it were done in a proper manner.
17 Q. HOW DOES IDAHO POWER DETERMINE AVOIDED ENERGY COSTS

18 UNDER THE CURRENT IRP METHOD?

19 A. Idaho Power uses the AURORA simulation model developed and marketed by

20 EPIS to perform the QF-in/QF-out computer simulations. The difference in costs

21 between the two computer simulations is used to derive the base energy cost. I

22 am not opposed to using an integrated third party model such as AURORA for
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 deriving avoided energy prices under an IRP method. I am opposed however, to

2 allowing a utility to use an internally developed model such as PacifiCorp's GRID

3 model. It requires far too many exogenous inputs, including internally developed

4 projected hourly market prices for each trading hub, that can influence the
5' resulting cost projection.
6 Q. IS IDAHO POWER PROPOSING ANY CHANGES TO ITS METHOD OF

7 DETERMINING IRP DERIVED ENERGY COSTS IN THIS

8 PROCEEDING?
9 A. Yes, Idaho Power is proposing several changes to the manner in which it will

10 calculate avoided energy prices under it proposed IRP method. Idaho Power is

11 proposing 1) to use just one AURORA computer simulation instead of two

12 simulations, 2) make post processing adjustments to the AURORA results to

13 remove market sales revenue impacts and assign the QF power an avoided energy

14 cost of $0/MWh during minimum load conditions, and 3) proposing ongoing

15 updates to many AURORA inputs between IRPs, including changes in resource

16 costs, load forecasts, and including all newly signed QF and "queued" QF PPAs.
17 Q. DO YOU SUPPORT ANY OF THESE CHANGES?

18 I A. No. Avoided costs are defined at 18CFR, Section 292.101 as:

19 (6) Avoided costs mean the incremental cost to an electric

20 utility of electric energy or capacity or both which, but for

21 the purchase from the qualifying facility or qualifying

22 facilities, such utility would generate itself or purchase

23 from another source.
2411 In other words, an appropriate method for establishing the rates for energy and
Case No. GNR-E-1 1-03
May 2, 2012
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 18 of 45

1 capacity payments must reflect the cost that is avoided by purchasing the power

2 from the QFs. The best manner to implement this fundamental avoided cost "but

3 for" pricing principle is through employing two production cost simulations.

4 With one simulation having the QF excluded from the resource mix and a second

5 simulation with the QF in the utility resource mix, the difference in cost

6 represents the costs that would have been incurred "but for" the QF. The costs

7 avoided due to the presence of the QF cannot be quantified under Idaho Power's

8 single "QF-in" computer simulation. To correct for this 'one-model-run' bias,

9 Idaho Power proposes a series of inappropriate post processing adjustments.
10 Q. PLEASE EXPLAIN THE POST PROCESSING CALCULATIONS IDAHO

11 POWER IS PROPOSING IN ORDER TO DETERMINE AVOIDED

12 ENERGY COSTS UNDER ITS PROPOSAL.

13 A. Idaho Power uses the AURORA-generated hourly dispatch of its resources and

14 market purchases to determine its highest cost displaceable resource in any hour

15 to determine the incremental cost for that hour. If there are no displaceable

16 resources due to the thermal resources operating at the minimum generation levels

17 set by Idaho Power, including a substantial minimum value for Langley Gulch,

18 Idaho Power's method assigns a $0/MWh incremental cost value for those hours.

19 The resulting stream of hourly incremental costs is then used along with the

20 estimated delivery patterns to derive the avoided cost prices for each QF type

21 shown in Idaho Power's Exhibit 8. Significantly, as noted in the testimony of

22 Idaho Power, under this proposed IRP method, no credit to the QF for opportunity

23 sales that arise from the availability of the QF power is recognized. The
Case No. GNR-E-1 1-03
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 19 of 45
3
4
5
6
7
8
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following table compares the avoided energy prices under Idaho Power current
IRP method with the proposed method.
Comparison of 20-Year Levelized Energy Costs
($IMWh)
'PC
Current IPC
IRP Proposed
Resource Type Method IRP Method Difference
Baseload $49.96 $43.82 -$6.14
Canal Drop $47.27 $45.45 -$1.82
Solar $48.33 $40.99 -$7.34
Wind $41.60 $35.86 -$5.74
The source of the avoided cost energy values under the column labeled "IPC
Current IRP Method" are from Idaho Power's Exhibit 8. The values under the
column labeled "IPC Proposed IRP Method" are from Idaho Power's response to
Staff Production Request No. 13. The energy values in both columns include the
integration cost adjustment.
Q. DO YOU BELIEVE IDAHO POWER'S PROPOSED IRP ENERGY
PRICING PROPOSAL IS CONSISTENT WITH PURPA AND HOW
AVOIDED ENERGY PRICES SHOULD BE DETERMINED?
A. No. PURPA imposes a must take obligation on the utility and provides only very
limited circumstances under which a utility can curtail purchases from a QF. In
deriving avoided energy prices under an IRP like methodology, the complete
change in the incremental cost incurred by the utility, including additional short-
term sales opportunities, are the costs incurred "but for" the QF. Idaho Power is
alleging that "the absence of any reference to sales in determination of avoided
Case No. GNR-E-1 1-03
May 2, 2012
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 20 of 45
I
2

1 costs" is a "significant aspect of the definition" with reference to Section

2 292.101(b)(6). (See Bokenkamp page 9). In my view, the absence of any

3 reference to sales is not significant and cannot be harmonized with the utility must

4 take obligation. The two AURORA production simulations will determine the

5 appropriate hourly value of the QF power including under what Idaho Power has

6 claimed are minimum load conditions. Idaho Power's proposals to ignore

7 opportunity sales and replace minimum load hours with a zero value are

8 mappropriate.

9 The potential for gaming that can occur under Idaho Power's proposal is

10 also of concern. Idaho Power has included Langley Gulch in its analysis as a

11 must run resource with a substantial minimum load level. If the Commission

12 were to adopt Idaho Power's proposal, including this type of resource in the

13 analysis as must run would be inappropriate. I will address this further in

14 discussing Idaho Power's proposed Schedule 74 later in this testimony.
15 Q. WHY DO YOU OBJECT TO IDAHO POWER'S PROPOSAL TO ALLOW

16 VIRTUALLY CONTINUOUS UPDATING OF THE INPUTS UNDER THE

17 IRP METHOD?

18 A. I have three concerns with allowing unconstrained updating to the AURORA

19 inputs, in-between publication of IRPs. First of all, it could create a substantial

20 burden on the QF to have to analyze and evaluate the reasonableness of any

21 change made by the utility subsequent to the integrated resource planning process.

22 Second, it could allow for game playing by the utility, as there are many

23 modifications that could be made simply to produce lower prices for the QF.
Case No. GNR-E-11-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 Third, Idaho Power is proposing that any QF that has made a written inquiry

2 seeking avoided cost prices would be included as a contract or resource in the

3 proposed IRP method calculations. Undoubtedly, some of these inquiries would

4 not result in executed PPAs, and yet avoided cost prices would have been

5 calculated for other QFs based upon this faulty assumption. Yet, none of these

6 "inquiry-only" QFs will be used by Idaho Power in the preparation of its

7 subsequent IRP. All of these concerns are likely to result in numerous complaint

8 proceedings requiring Commission resolution under Idaho Power's proposed IRP

9 implementation method.
10 Q. WOULD LIMITED AVOIDED COST UPDATES BE ACCEPTABLE

11 BETWEEN TWO-YEAR IRPS?

12 A. Yes, updates should be allowed for two, and only two, factors. As I noted earlier,

13 a critical input in determining incremental costs in an AURORA simulation is

14 natural gas prices. Forward gas prices for up to 10 to 12 years can be tracked and

15 are readily obtainable from third-party providers such as NYMEX or ICE.

16 Accordingly, having a mandatory annual update to the published avoided energy

17 cost prices based on forecasts from one of these independent third party sources

18 would be acceptable. The annual gas price update should occur every twelve

19 months from the date Idaho Power's integrated resource plan is completed and be

20 based on the average forward prices from the prior month's trading days. For the

21 plan years that extend beyond the third-party forward period, the absolute change

22 in the monthly prices from the last reported year should be used for all subsequent
Case No. GNR-E-1 1-03
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 years to adjust the plan's value. As an example, if the most recent plan was

2 completed in June 2013, the utility would be required to provide revised avoided

3 cost prices by July 1, 2014 based upon the average forward prices from all trading

4 days occurring in May 2014. Assume the third party's forward price stream

5 ended as of December 2026. The updated plan values for 2027 and beyond would

6 be derived from taking the difference between the plan's monthly prices for 2026

7 and the third party's forward prices and applying this differential to the same

8 month for all subsequent plan years.

9 The second type of update to avoided cost prices that should be allowed is

10 for new QF PPAs. The very important distinction from Idaho Power's proposal is

11 that for the new QF to be considered as a change to the utility's IRP, it must have

12 executed a PPA with its associated obligations, as compared to the uncommitted

13 "queued" status Idaho Power has proposed. For published avoided costs, the QF

14 PPA update would be concurrent with the gas price update and would include all

15 QF PPAs that had been executed, and not included in, the most recently

16 completed integrated resource plan. For non-standard QF PPA price

17 development, all newly executed QF PPAs could be included in each successive

18 QF PPA simulation. Allowing these two very significant-- but also very limited

19 updates, should resolve a great deal of Idaho Power's pricing and contractual

20 commitment concerns.
21 Q. ARE THERE ANY ELEMENTS WHICH YOU BELIEVE HAVE BEEN

22 IMPROPERLY OMITTED FROM IDAHO POWER'S PROPOSED HIP

23 AVOIDED ENERGY PRICING METHOD?
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 23 of 45

1 I A. Yes. I believe carbon costs should be included in the avoided energy prices and it

2 must be clearly stated that under the IRP method any and all environmental

3 attributes ("EAs") are retained by the seller.
4 Q. WHAT ARE IDAHO POWER'S STATED REASONS FOR EXCLUDING

5 CARBON COSTS FROM THE AVOIDED ENERGY PRICE

6 CALCULATIONS?

7 A. Idaho Power claims there is uncertainty in what this future cost may be and that

8 the cost does not exist today.
9 Q. WHY DO YOU DISAGREE WITH THIS REASONING?

10 I A. There are several reasons. First, in the 2011 Plan, Idaho Power has included its

11 best estimate of carbon costs. The 2011 Plan assumptions are that carbon costs

12 could exist in 2015 and be $20 per ton escalating at 5% per year. Idaho Power

13 explains the basis of the inclusion as follows:

14 The purpose of the carbon adder is to account for all of the

15 costs in the price of energy produced by carbon-emitting

16 resources. (2011 IRP, page 73)

17 Avoided costs prices should include all cost elements as well. While I

18 acknowledge that there is greater uncertainty regarding the exact year for national,

19 state or region wide, carbon legislation, all utility resource plans I have seen

20 assume it will occur. As Idaho Power has included this cost in its resource

21 selection process as well, it should do the same for deriving avoided energy prices

22 using the carbon cost assumptions from the utility's latest resource plan.

23 Second, it is patently unfair for a utility such as Idaho Power to exclude
Case No. GNR-E- 11-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 24 of 45

1 significant cost elements simply because it claims there is uncertainty about the

2 cost level and the expected date of implementation. The uncertainty regarding

3 exact price level knowledge exists in other major avoided cost elements such as

4 projected coal and gas prices. It is unlikely that Idaho Power can say with virtual

5 certainty what its exact fuel cost for the Bridger coal plant will be in 2015 but it

6 has assumed a value in its proposed IRP avoided cost pricing method based upon

7 its best available estimate. This same best estimate approach should be used to

8 include carbon costs in the avoided energy prices.

9 Third, under either the current or proposed Idaho Power IRP pricing

10 methods, carbon resources are on the margin the vast majority of the time. To

11 ignore carbon costs would have a significant impact on the resulting avoided
12! energy prices. The following table illustrates this impact under Idaho Power's

13 current and proposed IRP methods.
Comparison of 20-Year Levelized Energy Costs
($/MWh)
Resource Type
B aseload
Canal Drop
Solar
Wind
IPC
Current
IRP
Method
$49.96
$47.27
$48.33
$41.60
Current IPC
IRP
w/Carbon
Costs
$63.57
$60.90
$62.00
$56.16
Difference
$13.61
$13.63
$13.67
$14.56
141 The source for the values under the column entitled "IPC Current IRP Method" is
1511 Idaho Power's Exhibit 8 while the source for the values under the column labeled
Case No. GNR-E-1 1-03
May 2, 2012
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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"Current IPC IRP w/Carbon Costs" come from Idaho Power's response to Staff
production request no. 12. The energy values in both columns include the
integration cost adjustment. As would be expected, the inclusion of carbon costs
increases the avoided energy costs by 27 to 35%, a substantial amount.
5 Q. PACIFICORP WITNESS PAUL CLEMENTS RECOMMENDS THAT
6 WHEN A QF SELLS RENEWABLE POWER TO A UTILITY, THE
7 ENVIRONMENTAL ATTRIBUTES, INCLUDING RENEWABLE
8 ENERGY CREDITS, SHOULD TRANSFER TO THE UTILITY, ALONG
9 WITH THE POWER. DO YOU AGREE?
10 A. Absolutely not. There are two critical reasons why the EAs should stay with the
11 developer. First, as was just discussed, the IRP pricing method is based upon the
12 incremental cost of a host of resources the vast majority of which are carbon
13 emitters being either gas or coal fired resources. None of the utilities in this case
14 are proposing to determine avoided costs based on the full cost of surrogate
15 renewable resources with EAs. As such, consistency and equity requires any
16 environmental attribute rights that are not being paid for should stay with the QF.
17 Second, FERC has been very clear that avoided cost rates are not intended to
18 compensate the QF for more than capacity and energy. In FERC Docket No.
19 EL03- 133 FERC stated the following with regard to renewable energy credits or
20 similar tradeable certificates ("RECs"):
21, 23......What is relevant here is that the RECs are
22 created by the States. They exist outside the
23 confines of PURPA. PURPA thus does not address
24 the ownership of RECs. And the contracts for sales
25 of QF capacity and energy, entered into pursuant to
26 PURPA, likewise do not control the ownerships of
27 RECs (absent an express provision in the contract).
Case No. GNR-E- 11-03
May 2, 2012
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 26 of 45
States, in creating RECs, have the power to
2

determine who owns the REC in the initial instance,
and how they may be sold or traded; it is not an
4 issue controlled by PURPA.
5 24. We thus grant Petitioner' petition for a
6 declaratory order, to the extent that they ask the
7 Commission to declare that contracts for the sale of
QF capacity and energy entered pursuant to
9 PURPA do not convey RECs to the purchasing
10 utility (absent an express provision in a contract to
11 the contrary). While a state may decide that a sale
12 of power at wholesale automatically transfers
13 ownership of the state-created RECs, that
14 requirement must find its authority in state law, not
15 PURPA. (see EL03-133, Order issued October 1,
16 2003, paragraphs 23 and 24)
17 As Idaho does not have a state renewable portfolio standard and FERC has stated
18 that PURPA pricing does not include a value for EAs, this Commission should
19 clearly state that the published standard prices do not compensate the seller for
20 any EAs and that the rights to the EA remain the QF's.
21 Q. PLEASE SUMMARIZE YOUR RECOMMENDATIONS WITH RESPECT
22 TO DETERMINING AVOIDED ENERGY PRICES.
23 A. Properly implemented, published avoided energy costs could be determined using
24 either a surrogate resource or an integrated resource plan method. However, if an
25 1RP method is to be used, it should be done: 1) using a third-party production
26 simulation model such as AURORA, but not an in-house model such as
27 PacifiCorp's GRID, 2) the energy cost should be based on the difference between
28 the two computer simulations ("QF-in/QF-out"), 3) no "post processing"
29 calculations such as proposed by Idaho Power should be allowed, 4) between
30 integrated resource plan periods mandatory annual scheduled updates should be
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 27 of 45

1 done to incorporate current forward gas prices from a third party source and

2 additional executed QF PPAs but no other changes should be allowed, 5) carbon

3 costs should be included in the computer simulations consistent with the latest

4 utility integrated resource plan assumptions, and 6) based on the IRP method and

5 consistent with FERC rulings, all EAs, such as renewable energy certificates, are

6 retained with the QF.
7 Q. HAVE YOU PREPARED A COMPARISON SHOWING THE IMPACT OF

8 YOUR AVOIDED ENERGY COST RECOMMENDATIONS AS

9 COMPARED TO THE COMPANY'S IRP PROPOSAL?

10 A. No, but I believe a reasonable approximation can be made using Idaho Power's

11 responses to Staff Production Request Nos. 12 and 13. These responses compare
12' Idaho Power's existing IRP method, including carbon costs, with the proposed

13 method. This table shows a substantial difference of 34-57% in the resulting
14' avoided energy costs. What cannot be shown in the table is the updating process

15 which would incorporate the latest gas price information and the impact of

16 additional executed QF PPAs as the method is implemented over time.
Comparison of 20-Year Levelized Energy Costs
($IMWh)
Current IPC
IPC IRP
Proposed w/Carbon
Resource Type IRP Method Costs Difference
Baseload $43.82 $63.57 $19.75
Canal Drop $45.45 $60.90 $15.45
Solar $40.99 $62.00 $21.01
Wind $35.86 $56.16 $20.30
Case No. GNR-E-1 1-03
May 2, 2012
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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Q. HAVE YOU REVIEWED IDAHO POWER'S PROPOSALS FOR
CALCULATING AVOIDED CAPACITY COSTS?
A. Yes. Idaho Power is proposing to continue to use its load resource balance
position based on existing and committed resources as a trigger for including the
cost of capacity in the avoided cost payments. Based on this approach, Idaho
Power is not reflecting capacity costs until July 2016 in its illustrative examples in
this proceeding. However, Idaho Power is proposing to use a different resource to
determine the capacity value. While Idaho Power has been using a CCCT, it is
now proposing to use a SCCT for the capacity cost. The difference is significant
as Idaho Power states its integrated plan shows a CCCT capital cost of $1,380/kW
and a SCCT cost of only $790/kW. As shown by Idaho Power's Exhibit 8 and the
below table, this resource change reduces the capacity related payments by 44-
45% for each of the illustrative technologies.
Comparison of 20-Year Levelized Capacity Payments
($/1'IWh)
Resource Current Proposed
Type CCCT SCCT Delta Reduction
Baseload $15.04 $8.27 -$6.77 -45%
Canal $33.04 $18.18 -$14.86 -45%
Solar $27.27 $15.16 -$12.11 -44%
Wind $1.48 $0.82 -$0.66 -45%
Q. DO YOU AGREE WITH IDAHO POWER'S PROPOSAL TO USE A SCCT
TO DETERMINE AVOIDED CAPACITY COSTS?
A. Yes. The appropriate avoided resource is dependent upon the particular needs of
1811 the utility including the existing resource mix and load shape. The peak hour
Case No. GNR-E-1 1-03
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 29 of 45
1
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1 monthly load and resource balance tables in Idaho Power's 2011 Plan show

2 substantial monthly surpluses in the non-summer months (October through May)

3 in each year of the planning horizon. The historical monthly peak loads from

4 2006 - 2010 of Idaho Power also indicate the relative sharp four-month seasonal

5 load shape. Further evidence is provided by the loss of energy study conducted

6 by the utility which indicates a non-zero probability of unserved energy occurring
only during the four summer months. These factors, coupled with the need to

8 integrate variable resources into the system on a real time basis, make a SCCT the

9 correct avoided resource at this time for Idaho Power. (It is important to note that

10 I am not recommending changes to Avista' s or PacifiCorp' s avoided capacity

11 resource.)
12 Q. DO YOU AGREE WITH IDAHO POWER'S PROPOSAL TO NOT

13 INCLUDE AVOIDED CAPACITY COSTS IN DERIVING AVOIDED

14 COST PRICES UNTIL THERE IS A SYSTEM NEED?

15 A. I agree with the concept for a new QF but I disagree in how it should be

16 determined. As previously noted, Idaho Power relies on a negative July deficit

17 from its latest integrated resource plan to trigger the inclusion of capacity costs.

18 Based on the 2011 Plan, Idaho Power started including capacity costs in its

19 avoided cost rate calculations in July 2016. In my view, this is a far too restrictive

20 test and is readily subject to gaming. To illustrate my concerns, the 2011 Plan

21 shows July peak deficits in years 2014 and 2015. In the case of 2014, the deficit

22 is only 1 MW while in 2015, the July deficit is 80 MW. The 2011 Plan shows a

23 2015 eastside purchase of 83 MWs just for the month of July in order to eliminate
Case No. GNR-E-1 1-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 30 of 45

1 the apparent capacity deficit. The possibility for Idaho Power to insert a one

2 month purchase to prevent a triggering of capacity costs and payments to QF is

3 troubling.

4 Idaho Power's loss of load analysis included in the 2011 Plan is much

5 more illustrative and a better benchmark or measuring tool with regard to capacity

6 needs. Idaho Power correctly notes that the industry standard for these types of

7 analysis is to plan for no more than a one day in ten year loss of load. Idaho

8 Power equates this metric to being "roughly equivalent to 0.5 to 1.0 hours per

9 year." (See 2011 Plan, page 119). The Idaho Power loss of load expectation

10 study ("LOLE Study") shows the following expected loss of load hours:
LOLE Study
(Preferred Portfolio)
Year Hours
2012 0.62
2013 1.54
2014 1.65
2015 1.92

11 This analysis indicates or suggests additional capacity is needed well before July

12 2016 in order to meet the industry reliability standard. It also demonstrates the

13 game that can be played, in assuming a one-month contract purchase during a

14 peak summer month, and its effect of deferring into the following year a QF

15 capacity purchase obligation.

16 Utility resource additions are recognized as having a certain "lumpiness"

17 that does not allow for a precise matching of resource size to need. This can be

18 illustrated with the planned 450 MW capacity addition from the Boardman to
Case No. GNR-E-1 1-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 31 of 45

1 Hemingway transmission addition. After this sizable addition, Idaho Power's

2 peak load resource balance studies show a July surplus for the next four years.

3 Under Idaho Power's proposed short contract term, a new QF that executed a 5

4 year contract for deliveries in 2013 —2017 would receive capacity payments for

5 just the last eighteen months of the contract (2016 and 2017). Now due to the

6 lumpiness of the resource addition, the QF' s follow-on 5 year contract for 2018 -

7 2022 would only reflect capacity payments in the last eighteen months once again
8 '
due to the July surplus caused by the transmission addition. It is highly likely that

9 a new QF would ever receive five years of capacity value over each and every

10 successor contract under Idaho Power's capacity triggering proposal. The

11 capacity provided by the QF would continually be displaced or "bumped out" of

12 the resource need stack by any other resource addition subsequent to the PPA

13 execution date.

14 A QF with an expiring PPA has this exact same issue and concern. For

15 example, there are several QF PPAs that expire in 2017 and 2018 that had initial

16 contract terms of 35 years. These resources have not caused the projected short-

17 term surplus and should not be penalized in the form of reduced capacity value

18 payments in a subsequent follow-on PPA. Existing QFs entering into follow-on

19 PPAs or contract extensions should be provided full avoided cost capacity value

20 each and every year. To not provide capacity payments to these resources in

21 follow-on contracts would be inequitable as compared to the treatment afforded

22 utility-owned resources.
Case No. GNR-E-1 1-03
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 32 of 45
1 Q. HOW CAN THIS SITUATION BE PREVENTED?
2 A. The best solution is to offer 20 year QF contract terms as I have recommended so
3 that after a relatively short surplus period, the new QF will receive capacity value
4 for all remaining contract years. If the Commission instead approves Idaho
5 Power's five-year maximum contract term, the Commission should provide full
6 capacity payments to all QFs in follow-on PPAs and need cannot be used as a
7 reason to deny a follow-on PPA.
8 Q. WHAT IS YOUR RECOMMENDATION FOR A REASONABLE
9 CAPACITY PAYMENT TRIGGER?
10 A. I recommend that instead of using a one-hour July peak trigger, the results from
11 the Idaho Power LOLE Study should be used. Specifically, avoided capacity
12 costs should be included in the avoided cost prices to QFs in the first year the
13 LOLE Study produces a probability equal to or greater than 0.75 hours.
14 Q. WHY ARE YOU RECOMMENDING THE LOLE STUDY RESULTS BE
15 USED FOR TRIGGERING CAPACITY PAYMENTS?
16 A. It is a more complete analysis by taking into account all hours of the year and in
17 particular all peak summer months. Idaho Power's approach places far too much
18 weight on a single peak hour.
19 Q. WHY ARE YOU RECOMMENDING A VALUE OF 0.75 HOURS?
20 A. It is the mid-point under Idaho Power's analysis that equates to the industry
21 standard of having sufficient capacity such that there will not be a loss of load
22 exceeding a one-day-in-ten-year probability.
23 Q. HOW IS IDAHO POWER PROPOSING TO REFLECT THE AVOIDED
Case No. GNR-E-1 1-03
May 2, 2012
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 CAPACITY COSTS IN THE PUBLISHED PRICES?
2 A. Idaho Power is proposing to include avoided capacity costs beginning with the

3 first month where the integrated resource plan shows a monthly deficit. Idaho

4 Power is proposing that avoided capacity costs be paid over each and every hour

5 (on-peak and off-peak periods) of every month. This can be seen by reviewing

6 Idaho Power's response to Staff production request no. 15. The attachment shows
7'the step-up in the heavy (on-peak) and light (off-peak) load prices occurring in
8'July 2016.
9 Q. DO YOU AGREE WITH THIS APPROACH?

10 A. No. First, while capacity value may not be provided in each and every year of a

11 PPA due to Idaho Power having sufficient capacity in the early years, the capacity

12 value should be levelized over all years of the PPA. This levelization will hold

13 rate payers harmless over the contract term but allow the QF larger upfront

14 payments when its investment is at its highest level. This is essentially no

15 different than the rate base treatment afforded a utility owned resource whereby

16 the revenue requirement associated with the return on the investment is at its

17 highest level at the start of commercial operation. Second, providing the same

18 capacity value in every month and every hour makes little sense for Idaho

19 Power's system. This is readily apparent from reviewing the monthly peak load

20 and resource balance tables in the 2011 Plan. Other than the summer months,

21 Idaho Power has substantial amounts of excess capacity. For Idaho Power, the

22 avoided capacity costs should be assigned and paid over the heavy load hours of
Case No. GNR-E- 11-03
May 2, 2012
Schoenbeck, Di
Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 34 of 45

1 the summer season when the capacity is needed. This should be done by

2 calculating a $/kWh amount for each QF type based on the expected heavy load

3 hour deliveries during the four summer months or through the establishment of a

4 separate $/kW value as is being proposed by Avista.

5 IV. OTHER IDAHO POWER TERMS AND CONDITIONS
6 Q. HAS IDAHO POWER MADE ANY OTHER PROPOSALS THAT WOULD

7 IMPACT QFS IN THIS PROCEEDING?

8 A. Yes. First, Idaho Power has proposed that a standard negotiating and contracting

9 process be established by the Commission. Second, the Company asks that it be

10 given the authority to curtail deliveries from QFs under proposed Schedule 74

11 (Idaho Power Exhibit No. 5) for operational reasons.
12 Q. WHAT IS IDAHO POWER'S PROPOSAL FOR STANDARDIZING THE

13 NEGOTIATING PROCESS?

14 A. Idaho Power has not provided a specific proposal on the structure of the process

15 or all the issues it might address. In response to Staff production request no. 3

16 regarding the proposal, Idaho Power noted that PacifiCorp's proposed Schedule

17 38 may be a good starting point but that adjustments to it will likely be required

18 based on the Commission decisions in this phase of the proceeding. The response

19 further states that Idaho Power will be submit a proposed tariff later in this

20 proceeding.
21 Q. DO YOU AGREE THAT STANDARD CONTRACTING TERMS AND

22 PROCEDURES SHOULD BE DEVELOPED TO FACILIATE THE QF

23 CONTRACTING PROCESS WITH IDAHO POWER?
Case No. GNR-E- 11-03 Schoenbeck, Di
May 2, 2012 Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
Page 35 of 45

1 1 A. Yes. As I previously noted, transaction costs for small QFs can act as a barrier for

2 project development. Transaction costs can be minimized by having standard

3 prices, term and conditions for deliveries along with a clear stated time table for

4 the QF contracting process.
5 Q. HOW WOULD YOU RECOMMEND THIS BE ACCOMPLISHED?

6 A. I recommend the Commission order a collaborative workshop process for the

7 utilities and interested parties to develop the necessary contracts and any needed

8 tariffs after the Commission's ruling in this phase of the proceeding. The process

9 should attempt to resolve as many issues brought by the participants as possible.

10 Any issues that cannot be resolved among the parties could then be brought

11 before the Commission or an agreed upon decision maker for resolution.
12 Q. PLEASE SUMMARIZE IDAHO POWER'S PROPOSAL TO CURTAIL

13 QFS UNDER SCHEDULE 74.

14 A. Idaho Power is seeking Commission approval to impose curtailments on QFs that

15 have a nameplate capacity greater than or equal to 10 MW or more and also have

16 generator output limiting controls ("GOLCs") when it is experiencing "must run

17 periods." Idaho Power is proposing to define must run periods as:

18 Those periods when the Company's system load

19 demand in the upcoming hours and days requires

20 that sufficient Base Load Resources will be on-line

21 and available to serve system load. (See proposed

22 Schedule 74)
231 Idaho Power is proposing to define "Base Load Resources" as:

24 Company-owned hydroelectric resources, including

25 all run-of-river generators and the Hells Canyon

26 Complex, coal-fired generating resources (Jim
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 Bridger generating plant, Valmy generating plant,

2 and the Boardman generating plant), and the

3 Langley Gulch power plant. (See proposed

4 Schedule 74)

5 Idaho Power describes the possible need to curtail as follows:

6 The Company may curtail the generation of an

7 applicable QF during Must Run Periods if, due to

8 operational circumstances, purchases from the

9 applicable QF would require the Company to

10 dispatch higher cost, less efficient resources to

11 serve system load or to make Base Load Resources

12 unavailable for serving the next anticipated load.

13 (See proposed Schedule 74)
14 Q. SHOULD THE COMMISSION APPPROVE IDAHO POWER'S

15 PROPOSED SCHEDULE 74?
16 A. No. There are several reasons why the proposed schedule should not be

17 approved. First, it unilaterally modifies otherwise negotiated and existing

18 contractual rights. Second, Idaho Power presents a very misleading picture of

19 FERC's rulings regarding operational curtailment rights. Finally, Idaho Power

20 mischaracterizes Langley Gulch as a must-run base load resource, which it is not.

21 Schedule 74 would give Idaho Power the unilateral right to curtail QFs

22 under existing contracts where no such provision has been included in the

23 contract. It seems patently unfair for Idaho Power to seek to impose a tariff that

24 is, in effect, a significant and adverse contractual modification. While many of the

25 QF generation interconnection agreements ("GIAs") require the QF to install

26 generator output limit controls (GOLCs) at their facilities, the same GIAs restrict

27 Idaho Power's ability to actually limit a QFs generation through GOLCs to
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 contingency and reliability events. Schedule 74 would now expand the

2 Company's use of GOLCs to also include interruptions for essentially economic

3 dispatch reasons. If Idaho Power wants the right to dispatch QFs, it should have to

4 negotiate PPAs that contain these rights, and compensate the QFs for this

5 dispatch.

6 The Idaho Power testimony also asserts there have been two state

7 commissions that have implemented the FERC "rule"—Florida and Nevada. In

8 the case evolving the Nevada commission, Idaho Power asserts the

9 implementation was due to the "direct result of the authority given to the Nevada

10 PSC by the FERC rule." (See Park, page 17). Idaho Power Exhibit No. 4 is the

11 resulting procedure for curtailing three QFs: Saguaro Power Company, Nevada

12 Cogeneration Associates 1 ("NCA 1") and Nevada Cogeneration Associates 2

13 ("NCA 2") (collectively, "Nevada QFs"). I am familiar with the contract terms of

14 NCA 1 and NCA 2 as RCS was asked to provide an opinion report on the possible

15 purchase of these facilities by Texaco, now Chevron, from Bonneville Nevada

16 Corporation in 1990. Our analysis included a review of the two long-term power

17 purchase agreements for NCA 1 and NCA 2 with Nevada Power Company.

18 These contracts contain a specific provision that allows for curtailment based on

19 operational circumstances up to a specified number of hours. Exhibit No. 4

20 should be viewed for what it truly is. At the time it was issued by the Nevada
21' commission, it established the conditions and procedure by which Nevada Power
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1 would implement the curtailment rights for all the Nevada QFs in an equitable

2 manner. It was issued in response to complaint proceedings brought by the

3 Nevada QFs due to disputes arising over utility requests for curtailment made

4 during 1993. The disputes continued for several years even after the initial

5 complaint proceedings.

6 Idaho Power's brief reference to the Florida commission ruling does not
7 : provide a complete picture of that decision. A critical Idaho Power omission is

8 the fact the utility's actions prior to seeking QF curtailments must include

9 "maximizing economic off-system sales" and that the utility had negotiated

10 curtailment provisions with "many of the QFs." Consequently, when it is

11 necessary to curtail QFs, the curtailments are to be sequenced from three groups.

12 The first QF group consists of QFs having PPAs with curtailment provisions. The

13 second QF group consists of "as-available" QFs and finally, the third group, if

14 needed, are firm QFs. Finally, the utility must still pay the QF the avoided

15 capacity rate during the curtailment periods. None of these provisions are

16 elements contained within Idaho Power's Schedule 74 proposal.

17 The existing Idaho Power QF PPAs I have reviewed do not contain

18 operational or economic curtailment provisions. Accordingly, Idaho Power's

19 request to unilaterally change the contractual terms by implementing Schedule 74

20 should not be approved by the Commission.
21 Q. HOW HAS IDAHO POWER NOT PRESENTED A COMPLETE

22 EXPLANATION OF FERC'S CURTAILMENT POSITION?
Case No. GNR-E-1 1-03 Schoenbeck, Di
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Northside Canal Company
Renewable Energy Coalition
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A. The Idaho Power testimony provides a very brief paraphrased comment on
FERC' s recent December 15, 2011 ruling in Docket Nos. ER05-. 1065-011 and
0A07-32-008 ("Entergy Order"). The complete pertinent paragraphs from the

El ruling state:
53. Exemptions to the statutory QFpurchase obligation

6 are limited. First, a utility can be relieved of its QF

7 purchase obligation under section 201(m) of PURPA, 16
US. C § 824a-3(m) (2006). This provision is not at issue

9 here, as Entergy has not claimed relief under section

10 210(m), nor filed a petition seeking relief.

11 54. Second, section 304(f)(1) of the Commission's

12 PURPA regulations, 18 C.F.R § 292.304(f)(1) provides,

13 with certain limitations, that a utility is not required to

14 purchase unscheduled QF energy "during any period

15 during which, due to operational circumstances, purchases

16 from qualifying facilities will result in costs greater than

17 those which the utility would incur if it did not make such

18 purchases, but instead generated an equivalent amount of

19 energy itself" Entergy argues that this provision entitles it

20 to curtail unscheduled QF energy purchases whenever
21 Entergy has exhausted the cost-neutral redispatch options

22 available to accommodate the purchase. However, section
23 292.304(f) provides for afar more limited exception to the

24 PURPA purchase obligation than Entergy claims.

25 55. In Order No. 69, which implemented section 304(f),

26 the Commission stated that that section was intended to

27 deal with a certain condition which can occur during light
28 loading periods, in which a utility operating only base load

29 units would be forced to cut back output from the units in
30 order to accommodate the unscheduled QF energy
31 purchases. The Commission stated that such base load

32 units might not be able to later increase their output levels
33 rapidly when the system demand later increased, resulting
34 in the utility needing to rely upon less efficient, higher cost
35 units. Section 304(f), when read in conjunction with the
36 relevant explanation in Order No. 69, applies only to such
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 low loading scenarios, and cannot be relied upon to curtail

2 purchases of unscheduled QF energy for general economic

3 reasons.

4 56 Many avoided cost rates are calculated on an

5 average or composite basis, and already reflect the

6 variations in the value of the purchase in the lower overall

7 rate. In such circumstances, the utility is already

8 compensated, through the lower rate it generally pays for

9 unscheduled QF energy, for any periods during which it

10 purchases unscheduled QF energy even though that

11 energy's value is lower than the true avoided cost. On the

12 other hand, for avoided cost rates that are determined in

13 real-time, such avoided costs adjust to reflect the low (or

14 zero or negative) value of the unscheduled QF energy,

15 allowing the QF to make its own curtailment decisions. In

16 neither case is the utility authorized to curtail the QF

17 purchase unilaterally. (Footnotes omitted)

18 A review of all the above paragraphs provides a different perspective on FERC' s

19 view on curtailing QF deliveries from that asserted by Idaho Power. Paragraphs

20 55 and 56 are particularly important. Paragraph 55 states that the utility must be

21 operating only base load units and that they would be "forced to cut back output."

22 Paragraph 56 notes that avoided costs are generally determined taking into

23 account the time value of purchases. By employing production simulation models

24 such as AURORA, the economic dispatch of the system, including during light

25 load hours, has already been taken into account in deriving the avoided cost

26 prices. In this circumstance, FERC states the utility has already been

27 compensated through the lower avoided cost payment for these periods.

28 An even handed reading of these FERC statements shows Idaho Power

29 Schedule 74 is not consistent with FERC's view on QF curtailment. First,
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 Langley Gulch would not be a base load resource as FERC is using that term.

2 FERC is referring to thermal resource that may not be able "to increase their

3 output levels rapidly." Langley Gulch can go from 0 to 150 MW in ten minutes.

4 This is certainly not the ramp rate FERC was assuming in terms of a base load

5 resource. In fact, the manufacture, Siemens, markets the Langley Gulch "flex

6 plant" configuration as the "best solution for peaking to intermediate duty
7: dispatch." Second, Idaho Power has not shown that it would be forced to cut back

8 its base load resources under Schedule 74. While Idaho Power may be in a

9 legitimate minimum load condition, surrounding service territories or balancing

10 areas may not be. Idaho Power may be able to execute a sale to another entity

11 instead of curtailing a legitimate base load resource. Finally, under Idaho Power

12 proposed IRP method, it has already included a zero price for QF deliveries

13 during minimum load conditions. To now also curtail the QF is the precisely the

14 double penalty FERC pointed out in paragraph 56 of the Entergy Order as being

15 inappropriate. For all these reasons, Idaho Power's Schedule 74 should be

16 rejected by the Commission. It is a poorly disguised effort to impose economic

17 curtailment on QF deliveries.

18 V. AVISTA AND PACIFICORP CONTRACTING MATTERS
19 Q. HAVE AVISTA OR PACIFICORP RAISED ISSUES YOU WOULD LIKE

20 TO ADDRESS?

21 A. Yes. Avista is proposing several issues that need to be addressed regarding

22 standard contract terms if they are to be decided in this contested proceeding as
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 opposed to a collaborative workshop process. These issues are: 1) how soon

2 before commercial operation can a QF execute a PPA, 2) when will the PPA

3 prices be set, 3) liquidated damage provisions and 4) utility termination rights.
4 Q. WHAT IS AVISTA'S PROPOSAL FOR HOW SOON A PPA CAN BE

5 EXECUTED PRIOR TO COMMERCIAL OPERATION?

6 A. Avista is proposing that once a QF has executed a PPA, it must be commercially

7 operable within five years. This is a reasonable amount of time subject to the

8 occurrence of a force majeure event. Force majeure events that are beyond the

9 control of either party should allow for an extension beyond the five year window.

10 With this understanding, the QF Companies would support Avista's

11 recommendation.
12 Q. WHAT IS AVISTA'S PROPOSAL REGARDING WHEN THE PPA

13 PRICES WOULD BE SET?

14 A. Avista is proposing that the PPA prices would not be locked-in until just two

15 years prior to commercial operation.
16 Q. IS THIS AN ACCEPTABLE PROPOSAL?

17 A. Absolutely not. This proposal is totally impractical. As the CAISO analysis

18 noted, California, and by extension the west coast, market prices cannot sustain

19 the development of new generating resources. A long-term contract is required in

20 order to ensure reasonable cost recovery. The PPA prices must be known and

21 "bankable" at the time of PPA execution. No new QF developer or owner would

22 be willing to invest the time and money to permit and construct a new facility if

23 the contract prices have not been locked-in. The Commission should reject
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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1 Avista's proposal to only lock in the prices just two years before commercial

2 delivery.
3 Q. WHAT IS AVISTA'S LIQUIDATED DAMAGE PROPOSAL?

4 A. Avista is proposing that all QF PPAs have liquidated damage deposit provisions

5 set at $45 per kilowatt of installed capacity when the PPA is executed.
6 Q. WHAT ARE YOUR VIEWS ON THIS PROPOSAL?

7 A. If the Commission is going to decide this issue now, instead of it being discussed

8 later in a workshop format, then I would offer another option for a more accurate

9 tie between liquidated damages and a particular type of QF or generating profile,

10 instead of the proposed flat $/kW assessment.

11 The crux of the issue, as correctly noted by Avista, is non-performance by

12 the QF thereby requiring the utility to procure replacement energy at perhaps a

13 higher price than the QF PPA. This issue can be readily and fairly dealt with

14 through a mark-to-market liquidated damage option. At the time of PPA

15 execution, the QF could elect to post a fixed $/kW amount or an amount based

16 upon the difference between the contract revenue payments and forward power

17 prices for a period of three years starting at the expected commercial operation

18 date. Under this mark-to-market option, updates would also have to occur to

19 capture forward price movements. I recommend these updates be required once

20 every three months (every calendar quarter) to ensure adequate security has been

21 posted by the QF throughout the licensing and construction period. With this
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Northside Canal Company
Renewable Energy Coalition
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additional liquidated damage option, the QF Companies would support the
inclusion of liquidated damage provisions in all QF PPAs.
Q. WHAT UTILITY TERMINATION RIGHT IS AVISTA PROPOSING?
A. Avista is proposing that a utility may terminate a QF PPA if it has missed its
schedule commercial operation date by 180 days.
Q. IS THIS A REASONABLE CONDITION?
A. Yes, as long as the delay is not due to a force majeure event. With this
understanding, the QF Companies would support Avista's termination
recommendation.
Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
A. Yes.
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Twin Falls Canal Company
Northside Canal Company
Renewable Energy Coalition
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BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA QF CONTRACT
PROVISIONS INCLUDING THE
SURROGATE AVOIDED RESOURCES (SAR)
AND INTEGRATED RESOURCE PLANNING
(IRP) METHODOLOGIES FOR
CALCULATING PUBLISHED AVOIDED
COST RATES
Case No. GNR-E-11-03
EXHIBIT 1101
QUALIFICATION STATEMENT
OF
DONALD W. SCHOENBECK
QUALIFICATIONS OF DONALD W. SCHOENBECK
1 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
2 A. Donald W. Schoenbeck, 900 Washington Street, Suite 780, Vancouver,

3 Washington 98660.
4 Q. PLEASE STATE YOUR OCCUPATION.
5 A. I am a consultant in the field of public utility regulation and I am a member of

6 Regulatory & Cogeneration Services, Inc. ("RCS").
7 Q. PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND AND

8 EXPERIENCE.
9 A. I have a Bachelor of Science Degree in Electrical Engineering from the University

10 of Kansas and a Master of Science Degree in Engineering Management from the

11 University of Missouri.

12 From June of 1972 until June of 1980, I was employed by Union Electric

13 Company in the Transmission and Distribution, Rates, and Corporate Planning

14 functions. In the Transmission and Distribution function, I had various areas of

15 responsibility, including load management, budget proposals and special studies.

16 While in the Rates function, I worked on rate design studies, filings and exhibits

17 for several regulatory jurisdictions. In Corporate Planning, I was responsible for

18 the development and maintenance of computer models used to simulate the

19 Company's financial and economic operations.

20 In June of 1980, I joined the consulting firm Drazen-Brubaker &

21 Associates, Inc. Since that time, I have participated in the analysis of various

22 utilities for power cost forecasts; avoided cost pricing; contract negotiations for

23 gas and electric services; siting and licensing proceedings; and rate case purposes

1 including revenue requirement determination; class cost-of-service and rate de-

2 sign.

3 In April 1988, I formed RCS. RCS provides consulting services in the

4 field of public utility regulation to many clients, including large industrial and

5 institutional customers. We also assist in the negotiation of contracts for utility

6 services for large users. In general, we are engaged in regulatory consulting; rate

7 work; feasibility; economic and cost-of-service studies; design of rates for utility

8 service and contract negotiations.
9 Q. IN WHICH JURISDICTIONS HAVE YOU TESTIFIED AS AN EXPERT

10 WITNESS REGARDING UTILITY COST AND RATE MATTERS?

11 A. I have testified as an expert witness in rate proceedings before commissions in the

12 states of Alaska, Arizona, California, Delaware, Idaho, Illinois, Maryland,

13 Montana, Nevada, North Carolina, Ohio, Oregon, Washington, Wisconsin and

14 Wyoming. In addition, I have presented testimony before the Bonneville Power

15 Administration, the National Energy Board of Canada, the Federal Energy

16 Regulatory Commission and publicly-owned utility boards and in court pro-

17 ceedings in the states of Washington, Oregon and California.