20120504Reading Direct.pdf

RECEIVED
ANDEMMSKM 2012 MY PM 3: 33
ATTORNEYS AT LAW
Tel: [phone] Fax: [phone] APQ c P.O. Box 7218 Boise, ID 83707 - 515 N. 27th St. Boise, ID 83702 UTLflES
May 4, 2012
Ms. Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
472 W. Washington
Boise, ID 83702
RE: GNR-E-11-03 -Direct Testimony and Exhibits of Dr. Don Reading
Dear Ms. Jewell:
Enclosed please find the Prepared Direct Testimony and Exhibits of Dr. Don Reading,
submitted for filing in the above-referenced docket on behalf of Clearwater Paper
Corporation, J.R. Simplot Company, and Exergy Development Group of Idaho, LLC.
Per the Commission's Rules of Procedure, we have enclosed and original and nine (9)
copies, as well as a compact disc containing a copy of the testimony in word format.
Sincerely,
%~2~ Gregory M. Adams
Richardson & O'Leary PLLC
end.
RECEIVED
ffl 3: 34
Peter J. Richardson (ISB # 3195) IDAHc-LI L Gregory M Adams (ISB # 7454) L
II.L UOMISSIO Richardson & O'Leary, PLLC
515 N. 27th Street
P.O. Box 7218
Boise, Idaho 83702
Telephone: [phone]
Fax: [phone]
yeterrichardsonandoIeary.com
greg(richardsonand61eary.com
Attorneys for Clearwater Paper Corporation,
J.R. Simplot Company, and
Exergy Development Group of Idaho, LLC
BEFORE THE IDAHO
PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'S )
REVIEW OF PURPA QF CONTRACT ) CASE NO. GNR-E-1 1-03
PROVISIONS INCLUDING THE )
SURROGATE AVOIDED RESOURCE (SAR) )
AND INTEGRATED RESOURCE PLANNING)
METHODOLOGIES FOR CALCULATING )
PUBLISHED AVOIDED COST RATES. )
CLEAR WATER PAPER CORPORATION
J.R. SIMPLOT COMPANY
EXERGY DEVELOPMENT GROUP OF IDAHO, LLC
DIRECT TESTIMONY OF DR. DON READING
May 4, 2012

I 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.
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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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
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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I 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
obligation;
(6) That QFs own environmental attributes in Idaho QF contracts because the
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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transparent and effective method for estimating a utility's avoided cost rates.
2 Q. WHAT DID THE COMMISSION SAY ABOUT THE SAR METHODOLOGY
3 WHEN IT FIRST ADOPTED IT?

4 A. The Commission made it clear that it was laying a solid foundation for determining

5 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.'
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
1 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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the SAR methodology. Commission Staff in particular was helpful, as the Commission observed
2 in its order,
Staff admits that any method of administratively establishing avoided costs is "based, at
least in part, upon a fiction." In no small part, this is due to the vagaries of forecasting. One
of the advantages cited by Staff in the present SAR methodology is that it does not require a
detailed analysis of utility planned resources. Staff contends that a single Idaho avoided cost
rate would have the advantage of simplicity of application and administration. Although the
SAR method was described as consisting of seven steps, implementation of those steps
requires the Commission to establish at least 29 variables for computing avoided costs. The
set-point for most variables is selected from a range of reasonable values.
Staff recommends (1) maintaining the existing method of computing avoided costs,
(2) establishing a single avoided cost rate for all Idaho [sic.], and (3) establishing an
automatic method of periodically revisiting the variables.3
Numerous IPUC cases can be cited describing the rational for using the SAR methodology as a
reasonable and transparent method for determining avoided cost rates for the state's investor-
owned utilities.
Q. HAVE THERE BEEN ANY MAJOR CHANGES TO THE SAR METHODOLOGY
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
22 concluded that the avoidable resource should be changed to a natural gas-fired combined-cycle
23 combustion 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.
'I 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, W"-
E-93-10 (1995).
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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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The Company's position is that the current implementations of the SAR and IRP
methodologies are appropriate for the published and negotiated avoided cost rates,
respectively, as long as the 100 kW eligibility cap threshold for wind and solar
QFs is maintained for published SAR rates. The SAR methodology used for
calculating published avoided cost rates for smaller QFs continues to provide a
simple and transparent means of pricing that minimizes transaction costs a very
small QF might incur to negotiate a power purchase agreement. However, the
SAR methodology is not the best methodology as the QF project capacity
increases since it does not take into consideration the value a specific QF project
would provide to each utility's unique power system and does not account for the
characteristics of each individual QF.5
I certainly agree with Ms. Brown in that the SAR methodology continues to provide a simple and
transparent means of pricing and that it helps to keep the transaction costs down. I would add,
however, that the benefit of reduced transaction costs inures to both the QF developer AND the
utility.
Q. IS THE SAR METHODOLOGY WIDELY ACCEPTED?
A. Yes, even Idaho Power witness William Hieronymus seems to agree. He cites a 1992
National Economic Research Associates (NERA) survey that he states might be 20 years old but,
"still is representative of administratively determined avoided methods in use today. ,6 This
survey indicated that 14 states, out of 49 surveyed used some form of the proxy method in
determining avoided cost rates for PURPA projects. This indicates the SAR method is widely
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 ofMarginalAndAvoided Costs in Ratemaking; A
Survey, NERA (January 1992).
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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 .7 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 CCCT F Class scheduled to come on-line in 2014 and a CCCT H Class planned for 2010 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
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
12 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 defming avoided costs for a utility because of the way it
20 affects avoided or marginal costs in various time periods.
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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, Lormarginal costing purposes, the long-run marginal

23 costs gf generating capacity be used except in chronic cases of imbalance.

24 (emphasis added)10
25

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

M.
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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I 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
Id.,p.4.
12 Direct Testimony of Idaho Power Witness Karl Bokenkamp, GNR-E-1 1-03, p. 14.
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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
3 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
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
IPUC Order No. 29124, GNR-E-02-01 (2002).
14 Id..
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I 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-1 1-03, pp. 1 3-14.
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I 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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I 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-11-11 (2011).
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I 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 MW1I
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.
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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I 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.
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-1 1-03, p. 34.
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I 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 "IRP 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,
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.
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
Edison Electric Institute, PURPA: Making the Sequel Better than the Original (December 2006).
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I 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,
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 Staffs 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 Staffs methodology is employing the Differential Revenue Requirement
Method described above comparing the present value of the revenue requirements (PVRR) of the
base case with one that includes the utility's system including the QF. Items 6 and 7 of the
Stipulation state:
6.Finally, the present value of the QF project avoided cost is calculated by
subtracting the PVRR of the modified plan, with the costs of the QF set
to zero, from the PVRR of the base case resource plan.
7.Rates for capacity and energy from the QF project can then be developed for
which, on a present value basis, the expected payments to the QF are equal to the
project's avoided cost over the life of the contract .20
Note that item 7 states that the avoided cost rate for a QF is found by using both capacity and
energy. The end result is that Idaho has two methods for calculating avoided costs, the Proxy
method for smaller projects, and the Differential Revenue Requirement Method for larger
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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10
11
12
13
14
15
16
17
18
19
21
22
I 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?
12 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 RP.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 RIvIP'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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I 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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I 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 "IRIP 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
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 jLea 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 /MWh 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:
During many hours of the year, Idaho Power's highest displaceable incremental cost will
be set by one of its thermal resources. And because a thermal plant's heat rate changes
with load, the incremental costs also change with load. However, to simplify the analysis,
Idaho Power proposes use of the following assumptions:
1. Each thermal unit is assigned one incremental cost, which will be based on full load
operation, which applies all year long regardless of the loading level determined in the
AURORA analysis[.] (emphasis added)24
The problem with this approach, as Mr. Bokenkamp points out, is that heat rates change as
thermal units are ramped up and down. As the generating unit is backed down to follow load its
heat rate goes up and its efficiency goes down. Therefore, the cost per MWh of output goes up.
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-1 1-03, p. 25.
24 Id,p.24.
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16
17
18
19
20
21
22
23
24
25
26
27
NM
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 M short-run hourly basis. The Company also
12 makes additional "simplifying" assumptions that lower the price that will be offered to a QF. It
13 certainly does not put a PIIRPA 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?
3 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-1 1-03, 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
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 ofExisting State Avoided Cost Ratemaking
Methodologies in Supporting Alternative Energy Development andA Proposed Path for Reform, p. 24.
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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
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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I 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 $IMWh 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
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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* I 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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Levelized
Resource Type (Capacity Factor) Cost $/MWh Source
Langley Gulch [300 MM (65%) $111.13Staff Comments, IPC-E-09-34(Neal Hot Springs), 5/3/2010
CCCT lxi 1270 MW] 2011 IRP (65%) $98.00 IPC0 2011 IRP, p.47; without carbon adder of $10 $/MWh
Baseload -Current IRP Method [20MW] $65.00 IPC0 Memorandum in Support of Stay, p. 15, GNR-E-111-03
Baseload Proposed 11W Method [20MW] (92 0%*) $4740 IPC0 Memorandum in Support of Stay, p 15 GNR E 111 03
Baseload
Baseload -Proposed 1RP Method [20MW] (92.0%**)
Baseload -Current 1RP Method [20MW] I
CCCT lxi [270 MW] 2011 1RP (65%)
Langley Gulch 1300 MW] (65%)
$0 $20 $40 $60 $80 $100 $120
IRP Price Levelized $/MWh
I 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 RrvlP' 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 EIA'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 filly 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, GNR-E-1 1 -03,Table A, p. 5;
PacifiCorp's 2011 Integrated Resource Plan, Chapter 6.
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I 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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1 line date is more than 180 days beyond that stated in the contract.31 The rationale for the 180
2 day termination condition is the Company fears a developer may simply hold off bringing the
3 project on line if prices are falling and waiting for prices to hopefully increase. Mr. Kalich
4 supports the security provision because it creates a meaningful deterrent to delay in achieving the
5 proposed on line date. There are two major issues with what Avista (or any other utility) is
6 proposing for 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-1 1-03, 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).
Id.,p.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
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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I 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-1O-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
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 of Avista Witness Clint Kalich, GNR-E-11 -03, p. 33.
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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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I 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?

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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I 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
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. 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
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. AVTJ-E-08-04 (2008).
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1 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
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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I 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.
40 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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1 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, ¶ 24, Case
No. IPC-E-10-12.
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1 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 NorthWestern 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
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-1 1-03, 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,
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
Id., Exhibit No. 5, p.1.
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I 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
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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I 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
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.

47 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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I 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
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, GNR-E-1 1-03, p. 22.
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I 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
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.
Idaho Power Response to Exergy Production Request No. 19, contained in Exhibit 504.
Direct Testimony of Idaho Power Witness Tessia Park, GNR-E-1 1-03, p. 23, note 1.
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I 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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I 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., ¶ 6 (citing Montana Administrative Rule § 38.5.1903(1)).
45 Federal Register 12,214, 12,228 (1980).
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I 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
12 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
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.
Idaho Power Response to Exergy Production Request No. 2, contained in Exhibit 506.
Direct Testimony of Rocky Mountain Power Witness Paul Clements, GNR-E-1 1-03, pp. 7-10.
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I 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. IPC-E-11-15.
Direct Testimony of Rocky Mountain Power Witness Paul Clements, GNR-E-1 1-03, pp. 2-7 and Exhibit
202.
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I 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
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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I shorter timeframe than 45 days.
2 Q. DO YOU HAVE AN ALTERNATIVE PROPOSAL?
3 A. I orouose using the standard contracting tariffs arrnroved 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 PaciflCorp 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. 61
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 httlx//www.Dacificorp.cornles/cg/egfp.htrnl.
61
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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
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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I 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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I 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
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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I 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.
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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I 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 NorthWestern Energy "improperly sought to
4 assign all network upgrade costs to the QF instead of the amount of those costs that exceeded
5 what [NorthWestern 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
12 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 Application for Approval ofAvoided Cost Tarfffor New Qualifying Facilities,
Montana PSC Docket No. D2010.7.77, Order No. 7108e, p. 32, ¶ 84 (Oct. 19, 2011), available online at
http ://psc.mt.gov/DocsiElectronicDocuments/.
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I 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?
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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Don C. Reading

P ssupos.iIio n Vice President and Consulting Economist
Ed#r Jti n B.S.,Economics - Utah State University
MS.. Rconamics - University of Oregon
Ph.D., Economics— Utah State University
Omicron Deit -NSF Fellowship
Profesnonal Ben Johnson Associates, Inc.

a,dbrsinesi 1989F Vice President

bistoy 1986 Consulting Economist
Idaho Public Utilities Commission:
1981.86 Economist/Director of Pokv and Administration
Teaching:
1.90-8l Associate Professor, University of Hawaii-Nib
1970-80 Associate and Assistant Professor, Idaho State University
1968-70 Assistant Professor, Middle Tennessee-State University
Fxp e rie st e Dr. Reading provides expert testimony concerning economic and regulatory issues..
He has testified on more than 35 occasions before utility--.v _%ula tot y commissions in
Alaska, California. Colorado, ,the District of Co lumbia, Hawaii. ldaho,N'evada,
North Dakota, Texas, Utah, Wvormr.g, and Wathington.
Dr. R.eading has more than 30 tears experience in the field of economics; He has
participated in t}e development of indices rcflec ting economic trends, GNP growth
rates foreign exchange markets, the rnoncv supplv, stodt market vels,and
inflation. He has analyzed such public policy issues as the minimum wage, federal
spending and taxation, and import/export balances. Dr. Reading is one of four
economists providing yearly forecasts of statewide personal income to the Stare of Idaho.—for"'?,--purposes of establishing state personal income tax rates.
Tn -the fleId of telecommunication s, Dr. Readtighas proidtd exp tesiimofly-On
th outs of matinal cost, pricelast1cLtv, and measured rv.ice. r. Reading
prepasl a state-specific study of the price elasticity oldemand1br local tdepionc
seeve in Idaho and recently conducted research fuz,sad direced the preparation
of, a report to the Idaho legislature regarding the staisof tCCOmmUA&Cátk)ns
competition in that state.
Exhibit 501
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 1
Don C. Reading
Dr. Readings areas of expertise in the field of electric power include demand
forecasting, long-range planning, price elasticity, marginal and average cost pricing,
production-simulation modeling, and econometric modeling. Among his rent
cASes was an electric rate design analysis for the Industrial Customers of Idaho
Power. Dr. Reading is currently a consultant to the Idaho Legislature's Committee
on Electric Restructuring.
Since 1999 Dr. Reading has been affiliated with the Climate Impact Group (CIG) at
the University ofWashingson. His wodc with the CIG has involved an analysis of
the impact of Global Warming on the hydo facilities on the Snake River. It also
includes an investigation into water markets in the Northwest and Florida. In
addition he has analyzed the economics of snowmaking for ski area's impacted by
Global Warming.
Among Dr. Readings recent, projecti.,.&M a FERC hydropower recensing study (for
the Skokomish1ndi Tribe) anod. an anaIyis of Northern States Power's North
Dakota rate desn proposals affecgbrge industrial customers (ftjrJ.R..inpiOZ
Company). Dr.-Readrhas.9Lao pepned analysis for the Idaho Governor's
Office of the impact on the Northwest Power Grid of various plans to in*se
salmon runs in the Columbia River Basin.
Dr. Reading has prepared econometric forecasts for the Southeast Idaho Council of
Governments and the Revenue Projection Committee of the Idaho State Legislature.
He has also been a member of several N orthwest Power Planning Council tastical
Advisory Committees and was vice chairman of the Governor's Ecorsamic Research
Council in Idaho
V.0at J.dibç State University, Dr. Reading performed demographic Sidies umg a
cohoit/Survival model and several economic impac.tstudiesiz$ing iipUt/out)m
anaIys. He has also provided expert tcithony in cases conec ingloss of income
resulting from wrongful death, in jury, or employment discrimination. He is
currently a adjunct professor of economics at Boise State University (Idaho
economic history, urban /regional economics and labor economic.)
Dr. Reading has recently completed a public interest'wtr rightatranster case -fle is
currently a member of the Boise City Public WorksCommission.
Exhibit 501
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 2
Don-C. Rc2thn5
"Energizing Idaho", Idaho Issues Online, Boise State Utiithsity, Fall 2006.
The Economic Impact of the 2001 Salmon Season In Idaho, Idaho Fish and
Wildlife Foundation, April 2003.
The Economic Impact of a Restored Slrnon Fishery in Idaho, Idaho Fish and
Wildlife Foundation, April, 1999,
The Economic Impacrof Steelhead Fishing and the Return of Saltn Fibirg
Idaho, Idaho Fi *nWi1&ife Foundation, September, 1997.
"Cost Savings from Nuclear Resources Reforta: An Econamc ..ric.Model" (with E.
Ray Can terbery and Ben Johnson) Soe...oncmcJouwati0g1996.
A Visitor Analysis for a Birds of Prey Public Attraction, Peegti. àe1und1 Inc.,
November, 1988.
Investigation of a Capitalization Rate for Idaho Hydrø.à.aric Projects, IdboSUit
Tax Commission, June, 1988.
"Post-PURPA Views," In Proceedings of the N ARUC Biennial Regulatory
Conference, 1983.
An Input-Output Analysis of the Impact from Proposed Mining in the ChWS:A;á
(with R. Davies). Public Policy Research Center, Idaho State University, February
1980.
Pba.cp hate and Soathean'A S ocio EønsmirAn4si.c (with J. Eyre, et al). Government
Research Institute of Idaho State University and the StheastIdCó.ti•ilof
Governments, August 1975.
Ilstiii.zat11 General 14*1 Revenmes of the State ofidabo (with S. Gh azaafaraad D. Holley).
Center for Business and Economic Research, Boise State tlniversit Jne
"A Note.n.thDistthuthon f Federal Bxpanditures:An Interstate ..trparison,
1933-19.n•19&1496." In The A*ig"Sowmist,
VoL V;11IN.2 aIfl:97. , pp. 125-12&
".. tflY;a.d .tb..... xas, 19,3.:19." In JorwaI. . micHisto', VoL
QWI. Dëemhe* .I93pp. 792-810.
Exhibit 501
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 3
REQUEST FOR PRODUCTION NO. 261s1cl: Reference the Direct Testimony of
Mark Stokes, p. 18, describing the differential between what Idaho Power will pay for
PURPA generation in 2012 and the amount it would pay to purchase the same amount
of generation as a "firm" product in the Mid-C market.
(a)Please provide a detailed definition and an example of a "firm" product,
including the maximum term (years and months) for which Idaho Power could secure a
firm market purchase in 2012. Does this cost include the cost of firm transmission from
Mid-C to Idaho Power's system?
(b)Please estimate the amount of firm transmission (MW) Idaho Power
possesses or could secure from Mid-C to Idaho Powers loads.
(b)[sic] Using the same figures for the cost of firm market product used in
the testimony, please provide the differential for the cost for Langley Gulch (including all
variable and fixed costs passed onto customers through rates) for each year from 2012
to 2021, in dollars and in $/MWh. Please prorate the costs of market purchases for
2012 to account for the date Idaho Power estimates Langley Gulch costs will be
incurred by customers in that year.
(c)Please provide a detailed explanation of the assumptions used in the
calculation in the testimony and in the calculations in response to this request.
RESPONSE TO REQUEST FOR PRODUCTION NO. 26Isicl:
(a) The following is taken from the Western Systems Power Pool ("WSPP")
website (www.wspp.org) which includes information regarding energy trading in the
western United States:
The Current WSPP Agreement effective October 21, 2011, is
the most commonly used standardized power sales contract
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY - 41 Exhibit 502
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 1
in the electric industry. It is approved by the FERC and used
by jurisdictional and non-jurisdictional entities. Once signed,
the Agreement allows instant access to power trading within
the membership.
The mission of the organization is to provide a catalyst for an
efficient and robust wholesale electric power market. WSPP
accomplishes this by constantly facilitating refinements to the
Agreement and promoting trading relationships.
Under the WSPP Agreement, a "firm" product is defined as a firm capacity and/or
energy transaction whereby the Seller has agreed to sell or exchange and the
Purchaser has agreed to buy or exchange for a specified period available capacity with
or without associated energy which may include a Physically-Settled Option and a
capacity transaction in accordance with the Agreement, including Service Schedule C,
and any applicable Confirmation. The current maximum term at Mid-C on the ICE is
through the 2015 calendar year. The cost does not include transmission from Mid-C to
Idaho Powers system.
(b)Each month, the Idaho Power Delivery business unit notifies Idaho
Power's Power Supply business unit of the transmission allocations set aside to serve
network load for the next 14 months. Monthly amounts vary, but July has historically
been the most constrained month. The most recent report from Delivery indicates a
total of 134 MW of firm transmission capacity between Mid-C and Idaho Power is set
aside to serve network load in July 2012.
(b)[sic] Idaho Power has not performed this analysis or compiled the data
that would be required.
(c)The comparisons between the cost of PURPA generation and firm
purchases from the Mid-C market are based on the fixed contract price of PURPA
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -42 Exhibit 502
GNR-E-1 1-03
D. Reading: Simplot,
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Page 2
generation multiplied by the expected generation from each project on a monthly basis.
The Mid-C market comparison was done by taking the same amount of energy and
multiplying it by the same long-term forward price curve provided in the Company's
response to Exergy's Production Request No. 25[sic].
The response to this Request was prepared by M. Mark Stokes, Power Supply
Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEShjbjt5o2
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY - 43 GNR.E-1 1-03
D. Reading: Simplot,
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Page 3
REQUEST FOR PRODUCTION NO. 29(sicl: Reference the Direct Testimony of
Mark Stokes, p. 39, stating, "The estimated 20-year, levelized cost of Langley Gulch is
$68.55 per MWh using a 90 percent capacity factor assumption (to be consistent with
the SAR capacity factor assumption), and Idaho Power's current natural gas price
forecast."
(a)Please provide work papers and all cost assumptions for the $68.55 per
MWh figure for Langley Gulch, including interconnection and transmission costs, gas
price and transportation/storage costs, heat rate, assumed heat rate degradation,
equivalent availability factor, capital cost, variable O&M, fixed O&M, O&M escalation
rates, and inflation, as well as any other cost assumptions. Please provide the basis for
each assumption for each of the listed items.
(b)Please provide the levelized $/MWh cost of Langley Gulch for both energy
and capacity at the 84% capacity the Company expects the facility will have available
for planning purposes. Reference IPUC Order 30392, p. 17.
(c)Please provide the levelized $/MWh cost of Langley Gulch for both energy
and capacity at the 20 year average 49% capacity factor provided in Karl Bokenkamp's
Direct Testimony, p. 23.
(d)Please explain if Idaho Power will commit to pass onto its customers a 20-
year levelized cost for Langley Gulch that will not exceed the estimates above (allowing
for adjustment to customers' rates only to account for different capacity factors).
RESPONSE TO REQUEST FOR PRODUCTION NO. 29Fsicl:
(a) For questions (a), (b), and (c), please see the appropriate confidential file
provided on the confidential CD. The confidential CD will be provided to those parties
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUESE hbi 502
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY - G--1 1-03
D. Reading: Simplot,
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Page 4
that have executed the protective agreement in this matter. Calculations in each of the
three confidential spreadsheets include assumptions for all of the factors listed in
question (a) with the exception of heat rate degradation, which has no material impact
on the levelized production cost, and equivalent availability factor which is not
necessary to calculate the levelized cost of production. For question (a), please see the
confidential file, PURPA CCCT 90%.pdf, provided on the confidential CD.
(b)Please see the confidential file, PURPA CCCT 84%.pdf, provided on the
confidential CD. The confidential CD will be provided to those parties that have
executed the protective agreement in this matter.
(c)Please see the confidential file, PURPA CCCT 49%, provided on the
confidential CD. The confidential CD will be provided to those parties that have
executed the protective agreement in this matter.
(d)No.
The response to this Request was prepared by M. Mark Stokes, Power Supply
Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -48 Exhibit 502
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 5
REQUEST FOR PRODUCTION NO. 331s1c1: Reference the Direct Testimony of
Karl Bokenkamp, p. 25, describing Idaho Power's proposed assumption that each
thermal unit will assigned an incremental cost based on full load operation.
(a)is it true that when a thermal unit is operated at less than full load that the
incremental cost per MWh increases?
(b)For each of the Company's thermal units, please provide: (1) heat rate at
maximum output, (2) heat rate at minimum operating output, (3) incremental energy
cost at the heat rate in (1) and (2).
(c)For each of the Company's thermal units, please provide the number of
hours per year in the years 2008 through 2011 that the unit operated at full load
operation.
RESPONSE TO REQUEST FOR PRODUCTION NO. 331s1c1:
(a)It is true that when a thermal unit is operated at substantially less than full
load, the incremental cost per MWh does increase. This is because the efficiency of a
generating unit decreases when it is operated at substantially below its design loading.
However, depending on design of the individual unit, the highest operating efficiency
(the best or lowest heat rate) may occur at less than full load. This is similar to fuel
efficiency for your car - your car may be capable of running at 70 miles per hour, but
your best fuel efficiency may occur at 55 miles per hour.
(b)Please see the Excel file provided on the non-confidential CD.
(c)Please see the Excel file provided on the non-confidential CD. In addition
to providing the requested information, another analysis has been conducted to
determine the number of hours that each unit operated at or above 90 percent of full
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUES hbi 502
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY - 1-03
D. Reading: Simplot,
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Page 6
load. The number of hours of operation at or above 90 percent of full load provides a
good indication of the number of hours the units were operated at high loads.
The response to this request was prepared by Karl Bokenkamp, Director
Operations Strategy, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -54 Exhibit 502
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 7
IPUC Case No. GNR-E-11-03
Idaho Powers Response to Exergys Second Production Request
Response to Request for Production No. 33
33(b) For each of the Company's thermal units, please provide: (1) heat rate at
maximum output, (2) heat rate at minimum operating output, (3) incremental
energy cost at the heat rate In (1) and (2).
Incremental Incremental
Heat Rate at Heat Rate at Assumed Assumed Energy cost at Energy cost at
Normal Full Load Min Op. Output Fuel Cost Variable O&M Cost Max Output (full load) Mm. Op. Output
(Btu/kWh) (Btu/kWh) ($/MMBtu) ($/MWh) ($/MWh) ($/MWh)
Jim Bridger Unit #1 9,791 11,951 2.01 0.57 20.21 24.55
Jim Bridger Unit #2 10,661 11,921 2.01 0.57 21.96 24.49
Jim Bridger Unit #3 10,068 12,075 2.01 0.57 20.77 24.79
Jim Bridger Unit #4 10,913 11,957 2.01 0.57 22.46 24.56
Boardman 9,600 11,250 1.79 0.81 17.97 20.92
Valmy Unit #1 10,000 11,300 2.51 1.55 26.64 29.90
Valmy Unit #2 9,500 10,800 2.51 1.55 25.38 28.64
Danskin Unit #1 10,446 11,901 4.62 3.03 51.32 58.04
Danskin Unit #2 12,944 12,944 4.62 2.88 62.71 62.71
Danskmn Unit #3 13,115 13,115 4.62 2.88 63.50 63.50
Bennett Mountain 10,572 12,045 4.62 3.03 51.90 58.71
Notes:
1.Heat rates are approximate and are dependent on a number of factors.
2.Heat rates are for normal full load operation and normal minimum operational loadings.
3.For Valmy, the Operating Procedures Criteria (OPC) specifies how each owner's coal consumption is assigned based on usage.
4.Fuel costs are estimates and are based on values used in previous AURORA analyses. Fuel costs have a significant
impact on incremental cost.
5.Variable O&M costs are approximate and are based on values used in previous AURORA analyses
6.Output of combustion turbines varies with temperature (output decreases as temperatures increases). The above
estimates are based on an ambient temperature of 59 degrees F.
7.For Danskin Unit #1 and Bennett Mountain, minimum load is 60% of the full load output.
8.Because of their lower output and efficiency, Danskin Unit #2 and #3 are not currently operated at
reduced loading levels - i.e., their normal normal minimum operating output is fully loaded.
9.Salmon diesels not included in this response.
Exhibit 502
GNR-E-1 1-03
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Exergy, Clearwater
Page 8
IPUC Case No. GNR-E-11-03
Idaho Powers Response to Exergy's Second Production Request
Response to Request for Production No. 33
33(c) For each of the Company's thermal units, please
-

provide the numberof number of hours per year in the
years 2008 through 2011 that the unit operated at full load.
Unit
Number of hours lPCo operated its share of each unit -
at >= full load (net dependable capacity)
2008 2009 2010 2011
Jim Bridger Unit #1 597 729 1,934 200
Jim Bridger Unit #2 1 1,338 1,120 314
Jim Bridger Unit #3 399 1,749 988 478
Jim Bridger Unit #4 1,176 1,459 1,758 314
Boardman 493 28 1,107 899
Valmy Unit #1 834 18 882 769
Valmy Unit #2 5,733 1,668 1,003 515
Danskin Unit #1 83 36 65 40
Danskin Unit #2 11 40 - 14
Danskin Unit #3 5 38 11
Bennett Mountain 36 98 37 52
Unit
Number of hours IPCo operated its share of each unit
at >= 90% of full load (net dependable capacity)
2008 2009 2010 2011
Jim Bridger Unit #1 6,538 6,086 4,786 3,176
Jim Bridger Unit #2 6,969 5,803 6,744 3,321
Jim Bridger Unit #3 7,298 6,628 6,382 2,615
Jim Bridger Unit #4 5,641 6,535 6,470 3,365
Boardman 6,882 5,535 7,152 4,192
Valmy Unit #1 6,411 5,447 4,176 1,251
Valmy Unit #2 6,387 6,463 3,205 948
Danskin Unit #1 721 636 560 369
Danskin Unit #2 34 48 16 20
Danskin Unit #3 20 43 16 16
Bennett Mountain 125 489 218 213
Notes:
1.This analysis considers the operation of Idaho Power's share of each unit (Salmon diesels not included).
2.Ratings for several units have changed slightly over the time period
in question. For this analysis, the ratings used for full load are as follows:
Unit
Total Plant. Full Load Rating
(net dependable capacity. MW)
2008 2009 2010 2011
Jim Bridger Unit #1 530 530 530 531
Jim Bridger Unit #2 530 530 527 527
Jim Bridger Unit #3 530 530 530 523
Jim Bridger Unit #4 530 530 530 530
Boardman 585 585 575 575
Valmy Unit #1 249 249 249 249
Valmy Unit #2 270 270 270 270
Danskin Unit #1 171 171 171 171
Danskin Unit #2 45 45 45 45
Danskin Unit #3 45 45 45 45
Bennett Mountain 164 164 164 164
Idaho Power share of Bridger is 1/3, Boardman is 10% and Valmy is 509 16.
Exhibit 502
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 9
REQUEST FOR PRODUCTION NO. 37Fsicl: Reference the Direct Testimony of
Karl Bokenkamp, p. 29, "Idaho Power proposes that any QFs with signed contracts and
any 'queued' QFs be included in Idaho Power's resource portfolio for purposes of
calculating future avoided costs because they can impact future avoided costs. For
purposes of calculating avoided costs, Idaho Power proposes that upon Its receipt of a
written request from a CIF for contract pricing, the QF is designated as 'queued."
(a)For the years 2008 through 2012, please identify the QFs from whom
Idaho Power has received a written request for contract pricing with IRP methodology
rates (using numbers or other identifiers to preserve confidentiality if necessary).
(b)For each of the projects listed in response to (a), please provide the date
of the request for pricing, and whether the QF executed a PPA with Idaho Power for the
project, and whether the IPUC has approved the PP A for which pricing was requested.
RESPONSE TO REQUEST FOR PRODUCTION NO 371sic:
(a) - (b) Idaho Power does not keep detailed historical records of all
requests received that do not evolve into a completed purchase power agreement.
However, below is a list of projects that Idaho Power has recollection of making these
requests in recent years.
Resource
Type
Proposed
MW
Individual Project Detail
Date of Request Contract status
Cogen 97.00 Nov-Il
Hydro 2.25 Feb-12
Solar 20.00 Sep-11
Solar 60.00 2008, 2010 and 2012
Solar 20.00 Mar-11
Solar 20.00 Mar-Il
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -60 Exhibit 502
GNR-E-1 1-03
D. Reading: Simplot,
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Page 10
Solar 20.00 Nov-11
Solar 20.00 Nov-1 I
Solar 20.00 Nov-1 I
Solar 40.00 Jun-lI
Solar 35.00 Sep-il
Wind 80.00 Sep-11
Wind 38.00 Sep-08 Approved Contract,
Project on-line
Wind 80.00 Jan-10 Approved Contract,
Project on-line
Wind 60.00 Sep-1 I
Biomass 3.00 Nov-10 Approved Contract
Biomass 22.00 Jul-1 1 Approved Contract
Solar 20.00 Oct-10 Approved Contract
Wind 40.00 Jan-Il Approved Contract
Wind 24.00 Sep-1 I
Total 721.25
The response to this Request was prepared by Randy C. Aliphin, Energy
Contract Coordinator Leader, Idaho Power Company, in consultation with Donovan E.
Walker, Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST-xhibit 502 OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -61 GNR-E-1 1-03
D. Reading: Simplot,
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Page 11
Year Danskin
2008 106
2009 86
2010 77
2011 85
Bennett Mountain
45
62
32
44
REQUEST FOR PRODUCTION NO. 39[sIc]: Reference the Direct Testimony of
Karl Bokenkamp, p. 22, proposing that an SCCT replace a CCCT for purposes of
calculating the capacity component of the IRP Methodology calculation.
(a)For the years 2008 through 2011, please provide the number of days per
year that Idaho Power operated its gas peakers (Bennett Mountain or Danskin) to meet
load.
(b)Please provide the number of days per year that Idaho Power forecasts to
use Langley Gulch to meet load requirements, as assumed in Idaho Power's load and
resource balance from its IRP.
RESPONSE TO REQUEST FOR PRODUCTION NO. 39[sicJ:
(a) The number of days that Idaho Power operated its gas peakers to meet
load for the years 2008 through 2011 is as follows:
(b) Idaho Power's Monthly Average Energy Load and Resource Balance
(2011 IRP Appendix C, pages 22 through 41) and Idaho Power's Peak-Hour Load and
Resource Balance (2011 IRP Appendix C, pages 44 through 63) do not forecast the
number of days that Langley Gulch will be used to serve load. These resource
balances primarily compare the amount of forecast monthly energy (or peak-hour
capacity) available from each specific resource to serve the forecast monthly average
load (or peak-hour load).
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -64 Exhibit 502
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 12
For the number of days that Langley Gulch operates as determined in an
AURORA analysis which models the 2011 IRP preferred portfolio under 50th percentile
(median) water condition and load conditions with updated natural gas and load
forecasts and no carbon taxes, please see the Excel file provided on the non-
confidential CD.
The response to this request was prepared by Karl Bokenkamp, Director
Operations Strategy, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUES xhibjt5o2
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY - 65 GNRE1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 13
39(b) Please provide the number of days per year that Idaho Power forecasts
to use Langley Gulch to meet its load requirements, as assumed in Idaho
Power's load and resource balance from its IRP.
Number of days per year
that Langley Gulch
operates as determined
Year by AURORA analysis
2013 320
2014 315
2015 343
2016 359
2017 358
2018 352
2019 358
2020 357
2021 359
2022 364
2023 363
2024 361
2025 362
2026 363
2027 362
2028 366
2029 363
2030 363
Notes:
1. The AURORA analysis does not determine whether the generating units output is being used to
serve system load or if it is being used to support market sales.
Exhibit 502
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 14
REQUEST FOR PRODUCTION NO. 41: Reference the Direct Testimony of Karl
Bokenkamp, p. 29, lines 6-8. Please state whether Idaho Power intends for all "queued"
Us, as defined in the testimony, to be included in Idaho Power's IRP for all purposes,
including prudency of the decision to build a new utility-owned plant in a CPCN
proceeding for the DSM investments. Please explain how including all "queued" QFs in
the load and resource balance for all purposes will impact future utility plant CPCN
applications and DSM proposals, and other action items in the IRP.
RESPONSE TO REQUEST FOR PRODUCTION NO. 41: Historically, Idaho
Power has only included signed qualifying facility ("QF") contracts in the load and
resource balance used to prepare the Integrated Resource Plan ("IRP") because of the
uncertainty surrounding if and when additional projects may come on-line. Idaho
Power's need for new resources, both supply-side and demand-side, is driven by peak-
hour load growth. As long as the vast majority of new QF projects continue to be wind
resources, Idaho Power does not believe the "queued" QF projects would impact future
utility plant Certificate for Public Convenience and Necessity applications, demand-side
management proposals, or other IRP action items.
If Idaho Power had included a total of 700 megawatts ("MW") of QF wind in the
load and resource balance used in the preparation of the 2011 IRP, the resulting
preferred portfolio would likely be unchanged. Because wind resources can only be
counted on to provide 5 percent of nameplate capacity towards meeting peak-hour load,
700 MW of wind only displaces 35 MW of summertime capacity needs.
The queuing process as described in Mr. Bokenkamp's testimony would be used
to determine when the highest incremental cost displaceable resource has been fully
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -2 Exhibit 502
GNR-E-1 1-03
D. Reading: Simplot,
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Page 15
offset by the proposed OF projects. Once this level is reached, the model would be re-
run to include the cumulative OF project energy and determine the new highest
increment cost displaceable resource for each hour. The process of determining the
highest cost displaceable resource for each hour makes use of the most recent IRP
data, but does not change the IRP data or results. Therefore, for the IRP planning
process, Idaho Power would continue to use the forecast generation for all OF projects
with signed contracts.
The response to this Request was prepared by M. Mark Stokes, Power Supply
Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -3 Exhibit 502
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 16
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION:
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.:
IDAHO
GNR-E-1 1-03
Clearwater
Production Request
CW-1 1
DATE PREPARED
WITNESS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
4/30/2012
Clint Kalich
Clint Kalich
Energy Resources
[phone]
REQUEST:
Please provide all studies, analysis, or documents used to develop this $45/kw amount.
RESPONSE:
The $45/kW delay security amount is intended to create a source of liquid funds which the utility
can draw upon in the event that damages are incurred if a new project does not meet its online date.
A PURPA contract for Clearwater Paper's facilities do not require delay liquidated damages, as its
facility already is operating and Avista does not presently require its PURPA contracts to contain
delivery term or operating security.
In 2009, Avista commissioned a survey of utilities and their required delay (also referred to
"development") security amounts for renewable projects. The results are as follows:
Utility Security Level and
Structure
Security
Requirements Based
on One Year or
Revenues, if
applicable
Operating Period
and/or Development
Security
Requirements ($/kW
equivalent)
PG&E 2009 RFO Development period $50/kW Development
security is $1 5/kW Security Minimum
upon contract
execution.
Development security
is $ 1001kW times the
capacity factor
(minimum of $50/kW)
once the contract is
approved by the CPUC
Delivery term security
is equal to 12 months
of revenue for a 20
year contract.
Southern California Edison Development period $30/kW Development
2009 RFP security is equal to Security
$30/kW for
intermittent resources.
Delivery term security
is equal to 5% of the
value of the total
energy payments in the
Exhibit 503
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 1
Page 2
contract.
San Diego Gas and Electric Two times estimated $7,884,000 $78.84/kW
2007 RPP annual production
times $15/MWh in
place for the entire
term of the contract
Public Service of Colorado $75/kW of design $7,500,000 $75/kW
(2003) maximum output
Public Service of $75/kW of design $7,500,000 $75/kW
Oklahoma/Southwestern maximum output
Electric Power Company
Southwestern Public Service Fixed amount of $3,965,000 [or $49.57/kW
Company and Llano $3,965,500 for 80 MW $4,957,000 per 100
Estacado Wind LP contract contract MW]
(12/2001)
Arizona Public Service $75/kW for both $7,500,000 $75/kW
Company development period
and operating period
security
Delmarva Power (second lien $80/kW $8,000,000 $80/kW
also required) (2007)
Hawaiian Electric Company Development period $3 0/kW Development
2008 Renewable RFP security is $3OIkW and Security
Operating Period
Security is $40/kW
Further, both Idaho Power and Avista presently include delay liquidated damage security deposits
of $45/kW. Rocky Mountain Power requires a delay liquidated damage deposit equal to the
greater of $45/kW, or the full value of the first 3 months of expected electricity deliveries. Avista
understands that a similar delay liquidated damages provision is defined for PURPA projects
selling power into Oregon. Therefore it would appear that it is common practice to I) apply
liquidated damages to PURPA contracts and 2) a $45/kW level is reasonable, as is evidenced by
practice in Idaho and other jurisdictions.
Exhibit 503
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 2
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 4/30/2012
CASE NO: GNR-E-1 1-03 WITNESS: Clint Kalich
REQUESTER: Clearwater RESPONDER: Clint Kalich
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: CW-13 TELEPHONE: [phone]
REQUEST:
Has Avista approximated its likely actual damages in the event that a QF were to delay its
projected online date beyond the 180 day limit specified in the testimony? Please identify all
likely costs and provide all work papers and analysis performed.
RESPONSE:
No. Such calculation would depend on the market conditions at the time of the contract.
Exhibit 503
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 3
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION:
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.:
IDAHO
GNR-E-1 1-03
Clearwater
Production Request
CW-14
DATE PREPARED:
WffNESS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
4/30/2012
Clint Kalich
Clint Kalich
Energy Resources
[phone]
REQUEST:
Has Avista ever guaranteed the online date of any of its utility-owned generation facilities, and
promised to issue a rate payer refund, or otherwise reduce rates for the amount of estimated
damages set at $45/kw or otherwise? If so, please explain the circumstances. If not, please
explain why QFs need to provide such ratepayer protections but the utility does not
RESPONSE:
Please refer to the answer to PR 15(e).
Exhibit 503
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 4
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: IDAHO DATE PREPARED: 4/30/2012
CASE NO: GNR-E-11-03 WITNESS: Clint Kalich
REQUESTER: Clearwater RESPONDER: Clint Kalich
TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: CW-15 TELEPHONE: [phone]
REQUEST:
Reference IPUC Order No. 30611, at p. 2, approving CWIP and AFUDC for the Reardan wind
farm, which Avista intended to reach commercial online status by year end 2011, and stating
"Avista believe[d] it [wa]s cost effective and prudent to secure land rights and equipment now,
even though actual construction will not begin until 2011."
(a)Please explain the status of the Reardan wind farm, whether it came online as projected in
2011, its approximate online date, and the reason for any delays.
(b)Please identify and provide the costs spent by Avista on the Reardan project to date.
Please identify any costs included in Avista's retail rates implicitly or explicitly.
(c)Please explain how Avista was able to change its plans for Reardan's projected online
date without compromising Avista's need to acquire RPS compliant generation to meet
Washington RPS targets. Did Avista acquire another RPS compliant resource instead of
Reardan?
(d)What were Avista' s actual costs incurred in the delayed or permanently deferred online
date for Reardan? Please provide all supporting work papers and an explanation.
(e)Will Avista provide rate payers a $45/kw delay damages refund if Reardan is not online
within 180 days of year end 2011, as projected in the application in Case No. AVU-E-08-04?
Please explain why or why not.
RESPONSE:
(a)Avista has delayed plans for construction of the Reardan wind project. The recent
acquisition of the Palouse Wind Farm through a competitive RFP meets our needs through
at least 2019. The Company continues to maintain the permitted Reardan wind project as
an option for future development and continues to collect data at the site.
(b)Please seethe attached spreadsheet entitled "Reardan_Costslhii_Mar_2012.xlsx." No
costs are currently included in retail rates related to the Reardan Wind Farm.
(c)Avista was able to change plans through the acquisition of the Palouse Wind Project that
meets our immediate needs for RPS resources.
(d)Please see response (b).
(e)No. The alignment of customer interests is different as between a PURPA fixed-priced
contract as compared to a utility-owned generation resource. As PURPA resources are
provided to a utility at a fixed contract price, that contract price does not vary based on the
actual cost of the PURPA generation project. To help ensure that fixed price benefit is
delivered, it is in customers' interest to have PURPA contract terms structured such that
Exhibit 503
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developer interests are aligned with customer interests. A utility, such as Avista, does not
provide a price guarantee for its utility-owned generation assets, but instead provides
long-term generation ownership value to customers at cost. In other words, customers
benefit from paying only actual costs over the life of a very long-term resource. In
contrast, the guarantees embedded in PURPA contracts define costs utility customers will
pay over the term of the agreement. A delay damages provision is a means to ensure that
developer and customer interests are aligned, and that customers receive the benefits from
the PURPA contract, consistent with the pricing and other terms and conditions that have
been guaranteed to the developer under the PURPA contract.
Exhibit 503
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REQUEST FOR PRODUCTION NO. 7: Please identify all PURPA OF projects
that are owned or partially owned by Idaho Power or any company affiliated with Idaho
Power. Please describe each project in detail including ownership percentages,
monthly production, in service date, power purchaser and location. Please describe the
impact on each such project Idaho Power's proposals in this docket will have if they are
adopted by the Commission in total.
RESPONSE TO REQUEST FOR PRODUCTION NO. 7: IDACORP owns Ida-
West Energy, a non-regulated subsidiary that owns and operates nine OF projects
under PURPA. Specific details related to these projects are provided in the two tables
below. If Idaho Power's proposals are adopted by the Idaho Public Utilities
Commission, the four Ida-West projects located in Idaho will be impacted to the same
extent as any other similarly situated OF projects with which Idaho Power has FESAs
under PURPA.
Nameplate In-Service
Project Name (MW) Location Power Purchaser Ownership Year
South Forks 8.20 Idaho Idaho Power 50% 1985
Hazelton B 7.70 Idaho Idaho Power 50% 1993
Wilson Lake 8.40 Idaho Idaho Power 50% 1993
Falls River 9.10 Idaho Idaho Power 50% 1993
Cove 5.00 California Pacific Gas & Electric 50% 1990
Burney Creek 3.50 California Pacific Gas & Electric 50% 1990
Ponderosa/Bailey 1.10 California Pacific Gas & Electric 50% 1990
Lost Creek 1 1.10 California Pacific Gas & Electric 50% 1989
Lost Creek 2 0.45 California Pacific Gas & Electric 50% 1989
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -10 Exhibit 504
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Project Name Jan Feb Mar
South Forks 0 0 0
Hazelton B 0 0 87
Wilson Lake 0 0 51
Falls River 2.627 1,957 2,652
Cove 2,055 2,448 3,609
Burney Creek 654 816 1,271
Ponderosa/Bailey 156 196 279
Lost Creek 1 559 509 587
Lost Creek 2 249 226 258
Estimated Monthly Production (MWh)
Apr May Jun Jul Aug Sep
1,498 4,160 4,815 5,484 5,173 3,942
1,418 3,390 4,087 4,689 4,319 3,211
1,532 3,926 4,664 5,298 4,826 3,656
4,922 6,350 6,255 4,702 4,314 3,803
3,228 2,590 1,140 194 6 2
1,429 1,304 509 28 0 0
292 506 538 324 66 3
562 550 492 498 502 493
247 247 234 226 237 229
Oct Nov Dec
2,272 0 0
1,373 51 0
1,639 57 0
3,713 3,538 2,842
16 235 1,353
4 45 266
0 16 92
528 513 528
241 230 238
The response to this Request was prepared by Mark Stokes, Power Supply
Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
DATED at Boise, Idaho, this 17 th day of February 2012.
DONAVON E. WAL ER
Attorney for Idaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST Exhibit 504 OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY.- 11 GNR-E-11-03
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REQUEST FOR PRODUCTION NO. 12: Reference the Direct Testimony of
Tessia Park, p 18, discussing the Company's proposed Tariff Schedule 74 (Exhibit No.
5).
(a)Please identify the provision of Idaho Power's proposed Tariff Schedule
74 that would compensate Us for curtailments occurring without providing the required
notice, or where the basis for the curtailment was not supported by the circumstances
described in 18 C.F.R. § 292.304(f). If no such provision is included, please explain
why.
(b)Please explain Idaho Power's basis for only proposing to provide Us
one-hour notice prior to such curtailments. Is Idaho Power aware of any FERC or state
commission order that has authorized advance notice of one hour or less to QFs in
implementing 18 C.F.R. § 292.304(f)?
(c)Does Idaho Power believe that it has the right to curtail Us to under 18
C.F.R. 292.304(f) even when the applicable QF contract provides for no such
curtailment? If so, please explain the basis for this position.
RESPONSE TO REQUEST FOR PRODUCTION NO. 12:
(a)Tariff Schedule 74 does not contemplate curtailing QFs without providing
the required notice. Since it is not Idaho Power's intent to curtail Us pursuant to
Schedule 74 without prior notice, no such provision was included.
(b)Because wind is intermittent and because QFs do not provide Idaho
Power with schedules for their generation, Idaho Power has no way of knowing how
much wind generation it is going to have on its system until usually the hour or even
minutes before a scheduled period. While Idaho Power is not aware of any Federal
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
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Energy Regulatory Commission ("FERC) or state commission order that has authorized
advance notice of one hour or less to Us in implementing 18 C.F.R. § 292.304(f),
there is nothing in the FERC rules which prohibits providing only one-hour notice.
(c) Yes, Idaho Power believes it has the right to curtail Us under 18 C.F.R. §
292.304(f) even if the applicable QF contract provides for no such curtailment. It is
Idaho Powers position that all FERC rules related to PURPA, including 18 C.F.R. §
292.304(f), apply to QF projects regardless of whether or not those rules are specifically
mentioned in the firm energy sales agreements Idaho Power has with PURPA
developers.
The response to this Request was prepared by Tessia Park, Load Serving
Operations Director, Idaho Power Company, in consultation with Jason B. Williams,
Corporate Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY - y Exhibit 504
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REQUEST FOR PRODUCTION NO. 13: Reference the Direct Testimony of
Tessia Park, p. 11, stating, "Based upon the current price of natural gas, dispatch costs
of Langley Gulch will be approximately $22."
(a)What is the current price of gas used to calculate the $22 Langley Gulch
dispatch cost?
(b)What is the price of gas Idaho Power expects to pay when Langley Gulch
comes on line the summer of 2012, and the expected dispatch cost at that gas price?
(c)What price of gas does Idaho Power expect to pay for Langley Gulch, and
what is the associated expected dispatch cost annually over the next 20 years?
(d)What is the fixed cost of Langley Gulch in $/MWh? What is the fixed cost
of a QF to the Company?
RESPONSE TO REQUEST FOR PRODUCTION NO. 13:
(a)A natural gas price of approximately $3/MMBtu results in an estimated
Langley Gulch dispatch cost of $22/megawatt-hour ("MWh").
(b)Current forward gas prices for July 2012 indicate a cost of $2.401MMBtu.
This would result in a Langley Gulch dispatch cost of $1 7.62/MWh.
(c)The 2011 IRP low-case, natural gas price forecast is currently viewed as
the best long-term forecast Idaho Power has available, although this forecast reflects
near-term gas prices that are higher than near-term forward market prices. This
forecast is relatively close to the most recent natural gas price forecast issued by the
Northwest Power and Conservation Council. The 2011 IRP low-case gas price forecast
and the resulting dispatch cost of Langley Gulch are provided through 2030, the end of
the 20-year planning horizon in the 2011 IRP, in the table below.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
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Langley Gulch
Gas Price Dispatch Cost
Year ($IMMBtu) ($IMWh)
2012 $4.60 $32.59
2013 $5.09 $35.89
2014 $5.43 $38.20
2015 $5.72 $40.22
2016 $6.03 $42.31
2017 $6.32 $44.27
2018 $6.59 $46.10
2019 $6.84 $47.83
2020 $7.14 $49.82
2021 $7.43 $51.85
2022 $7.57 $52.78
2023 $7.81 $54.42
2024 $8.10 $56.41
2025 $8.43 $58.65
2026 $8.76 $60.89
2027 $9.10 $63.17
2028 $9.47 $65.69
2029 $9.85 $68.30
2030 $10.24 $70.96
(d) The annual fixed costs of Langley Gulch over a 30-year life are presented
in the Excel file, Langley Gulch Fixed Costs, provided on the non-confidential CD.
Although the second part of the question does not specify or define what should
be considered a "fixed" cost for a OF contract, Idaho Power is assuming the fixed cost
of a OF contract would be the fixed rate contained in the contract. As presented on
page 8 of Company witness Stokes's testimony, the remaining future fixed cost of the
119 signed and approved contracts will be $3.6 billion throughout the term of the
agreements. Based on estimated generation of 44,414 GWh from these projects
throughout the term of the agreements, the average rate paid for this energy would be
$81 .06/MWh.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
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The response to this Request was prepared by M. Mark Stokes, Power Supply
Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -10 Exhibit 504
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REQUEST FOR PRODUCTION NO. 17: Reference the Direct Testimony of
Tessia Park, p. 7, stating, the limiting conditions on the amount of variable generation
from PURPA resources which Idaho Power can accommodate are not apparent during
periods of relatively high customer demand."
(a)Please define "relatively high customer demand" as used in this
statement.
(b)Please estimate the level of demand at which Idaho Power believes there
will be no limiting conditions for existing and contracted QFs.
(c)For the years 2010 and 2011, please provide the hours and days of the
year that Idaho Powers load fell below the level described in item (b).
RESPONSE TO REQUEST FOR PRODUCTION NO. 17:
(a)Relatively high customer demand is not defined by a specific numerical
value but rather when conditions exist such that load demands exceed the minimum
hydro and thermal generation on the system.
(b)Idaho Power is unable to forecast the level of demand at which time there
will be no limiting conditions for existing and contracted Us as the level of demand is
dependent on factors which the Company does not control, output of various Us, delta
between minimum and maximum load on a given day, and the hydro conditions.
(C) The Company has not prepared the analysis requested.
The response to this Request was prepared by Tessia Park, Load Serving
Operations Director, Idaho Power Company, in consultation with Jason B. Williams,
Corporate Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
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REQUEST FOR PRODUCTION NO. 19: Reference the Direct Testimony of
Tessia Park, p. 20, stating, "Pursuant to FERC licenses Idaho Power has for its run-of-
river hydro electric projects, the Company is obligated to take whatever generation flows
through them; it does not have the ability to decrease or increase the generation."
(a)Please identify each of the run-of-river hydro plants and provide the
capacity of each.
(b)Please provide the FERC license for each project (in electronic format if
available).
(c)Please identify the provision (page number, section number, as
applicable) in each FERC license that Idaho Power relies on to determine it does not
have the ability to decrease or increase the generation.
(d)For each plant, please explain whether the plant has the operational
capability to spill water without generating electricity, and any restrictions on Idaho
Power's ability to do so.
RESPONSE REQUEST FOR PRODUCTION NO. 19:
(a) Following are the run-of-river hydro plants and their capacity:
Milner — 59.45 MW
Twin Falls - 52.74 MW
Shoshone Falls - 12.5 MW
Upper Salmon Falls A —18 MW
Upper Salmon Falls B - 16.5 MW
Lower Salmon Falls —60 MW
Upper Malad - 8.27 MW
Lower Malad —13.5 MW
Bliss —75 MW
Swan Falls —25 MW
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
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(b)Electronic versions of the licenses identified above are provided in the
non-confidential CD.
(c)Milner. A complete reading of the Milner license shows that the Milner
project is designed to generate with flows that are not used for irrigation as they pass
through the project (run-of-river).
Twin Falls. A complete reading of the Twin Falls license shows that the
Twin Falls project is designed to generate with flows as they pass through the project
(run-of-river).
Shoshone Falls. A complete reading of the Shoshone Falls license shows
that the Shoshone Falls project is designed to generate with flows as they pass through
the project (run-of-river). See Article 401.
Upper Salmon Falls A. A complete reading of the Upper Salmon Falls
license shows that the Upper Salmon Falls project is designed to generate with flows as
they pass through the project (run-of-river). See Article 401.
Uer Salmon Falls B. A complete reading of the Upper Salmon Falls
license shows that the Upper Salmon Falls project is designed to generate with flows as
they pass through the project (run of river). See Article 401.
Lower Salmon Falls. A complete reading of the Lower Salmon Falls
license shows that the Lower Salmon Falls project is designed to generate with flows as
they pass through the project (run-of-river). See Article 401.
Upper Malad. A complete reading of the Malad license shows that the
Malad project is designed to generate with flows as they pass through the project (run-
of-river). See Article 401.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OFOF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -21 GNR-E-1 1-03
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Lower Malad. A complete reading of the Malad license shows that the
Malad project is designed to generate with flows as they pass through the project (run of
river). See Article 401.
Bliss. A complete reading of the Bliss license shows that the Bliss project
is designed to generate with flows as they pass through the project (run-of-river). See
Article 401.
Swan Falls. A complete reading of the Swan Falls license shows that the
Swan Falls project is designed to generate with flows as they pass through the project
(run-of-river).
In addition, the non-confidential CD contains a copy of a Settlement Agreement
between Idaho Power and the U.S. Fish and Wildlife Service which contains certain
environmental provisions that place constraints around how the Company operates the
Mid-Snake hydro projects (e.g.), Shoshone Falls, Bliss, Upper Salmon, and Lower
Salmon).
At run-of-river projects, generation increases as flow increases and generation
decreases as flow decreases.
(d) Each licensed facility has the physical capability to spill water without
generating electricity. The proposed operations in the applications for FERC licenses
and state water quality certifications did not include spill except when flows exceeded
plant capacity or when generators tripped off-line in emergency situations. To the
contrary, operations may require an amendment to the FERG licenses and/or state
water quality certifications.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
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The response to this Request was prepared by Lewis Wardle, Senior Biologist,
Idaho Power Company, in consultation with Donovan E. Walker, Lead Counsel, Idaho
Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
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REQUEST FOR PRODUCTION NO. 20: Reference the Direct Testimony of
Tessia Park, p. 23, stating, "the Company must maintain constant flows below Hells
Canyon dam for environmental compliance, thus limiting the ability to curtail generation
out of the Hells Canyon Complex to no less than approximately 350 MW."
(a)Please identify the individual plants/dams at the Hells Canyon Complex
and the MW capacity of each.
(b)Please explain the environmental compliance requirement for each that
limits the ability to curtail generation and provide the minimum generation of each
individual project. Please identify the government agency imposing the compliance
requirement.
(c)For each plant, please explain whether the plant has the operational
capability to spill water without generating electricity. Please explain why generation
cannot be curtailed to 0 MW by spilling, or to any cumulative output below 350 MW for
the Complex.
RESPONSE TO REQUEST FOR PRODUCTION NO. 20:
(a)The Hells Canyon Complex consists of three projects: Brownlee, Oxbow,
and Hells Canyon. The nameplate MW ratings for the aforementioned projects are as
follows: Brownlee-585.40, Oxbow-1 90.00, and Hells Canyon-391.50
(b)FERC:
Brownlee, Oxbow, Hells Canyon
. Minimum reservoir level
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Hells Canyon Dam
• Minimum flow 13,000 cubic feet per second ("cfs") at Lime
Point 95 percent of the time (flows less than 13,000 cis
must be negotiated with Corps of Engineers)
• Maximum ramp rate 1 ft. I hour
a Minimum instantaneous flow 5,000 cfs
Corps of Engineer ("COE"):
Hells Canyon Dam - Requested 13,000 cfs variance
• Minimum instantaneous flow 8,500 cis (measured at Snake
River at Hells Canyon) when previous 3-day moving
average Brownlee Reservoir inflow is at or above 8,500
cfa.
a Minimum instantaneous flow 11,500 cfs (measured at
Snake River below McDuff Rapids) unless it would require
drafting Brownlee Reservoir.
• When the previous 3-day moving average for Brownlee
Reservoir inflow is less than 8,500 cfs, the instantaneous
minimum Hells Canyon flow shall not fall below the
previous 3-day moving average for Brownlee Reservoir
inflow.
National Ocean Atmospheric Administration ("NOAA") - National Marine
Fishery Services: (Endangered Species ACT)
• Provide stable Hells Canyon outflow for salmon spawning
and establish minimum flow level for spring emergence.
. Provide minimum flow level for spring emergence.
• Perform entrapment surveys for spring emergence salmon
to mitigate 4" ramp rate.
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Environmental Protection Agency ("EPA") - State Department of
Environmental Quality:
• Maintain total dissolved gases ("TOG") below Hells Canyon
Dam below 110 Parts Per Million ("PPM")
United States Fish and Wildlife Service:
• Maintain TOG below 110 PPM to protect Endangered
Species Bull Trout.
(c) Power plants in the Hells Canyon project are not able to decrease
generation to 0 and spill water without generating electricity for the following reasons, as
per regulatory standard requirements:
North American Electric Reliability Corporation ("NERC") - Western
Electric Coordinating Council ('WECC"):
• NERC Standard BAL-002-1 Disturbance Control Standard
("DCS" ) - utilize contingency reserve to balance resources
and demand and return interconnection frequency within
defined limits following a reportable disturbance.
• WECC Standard BAL-002-WECC-1 Contingency Reserve
- provide reliable operation of the interconnected power
system. Adequate generating capacity must be available at
all times to maintain scheduled frequency, and avoid loss
of firm load following transmission or generation
contingencies.
• NERC Standard BAL-005-0.2b Automatic Generation
Control ("AGC") - provide necessary AGC to calculate
Area Control Error ("ACE") and to routinely deploy the
Regulating Reserve.
• WECC Standard BAL-STD-002-0 Operating Reserve -
provide adequate generating capacity to be available at all
times to maintain scheduled frequency and avoid loss of
firm load following transmission or generation
contingencies. This generating capacity is necessary to
supply requirements for load variations, replace generating
capacity and energy lost due to forced outages of
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generation or transmission equipment, meet on-demand
obligations, and replace energy lost due to curtailment of
interruptible imports.
FERC:
Maintain generation MW levels for undesignated sales.
Hells Canyon Dam TOG will elevate over 110 PPM for spill above 3000 cfs.
The response to this Request was prepared by Tessia Park, Director Load
Serving Operations, Idaho Power company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST Exhibit 504 OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -27
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REQUEST FOR PRODUCTION NO. 21: Reference the Direct Testimony of
Tessia Park, p. 1, stating dispatch costs for the Company's coal units are approximately
$30/MWh and for Langley Gulch are $22/MWh.
(a)Please explain why the Company would not take its coal plants ofiline and
instead run Langley Gulch during times when it expects to have light loading periods.
(b)For Langley Gulch, the run-of-river hydro projects, and the Hells Canyon
Complex, please provide the minimum and maximum output for each that Idaho Power
could reasonably expect to obtain during periods of the year that Idaho Power expects
to experience light loading events. Please explain the basis for the estimates for each
category.
RESPONSE TO REQUEST FOR PRODUCTION NO. 21:
(a)Coal plants cannot be shutdown and restarted on a daily basis and,
consequently, they can only be turned down to minimum generating levels during light
load periods in order to have their capacity available for the next days' heavy load
period.
(b)When on-line, Langley Gulch will typically be operated during light loading
events between its minimum and maximum generating levels. It is expected that
Langley Gulch will be dispatched somewhere between its minimum and maximum
levels depending primarily on system load, actual wind generation, and plant
economics. The minimum and maximum levels vary seasonally, but are reasonably
expected to be about 160 MW and 300 MW, respectively.
The minimum and maximum output for the run-of-river hydro projects during light
loading events is dependent on water conditions in the Snake River Basin as no
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significant reservoir storage is available at any of Idaho Power's projects. The water
conditions are very predictable with respect to short-term planning; however, a longer-
term basis review of Snake River Basin streamfiow records indicates pronounced
season-to-season and year-to-year variability. Therefore, expected minimum and
maximum output levels depend on the type of water year. For capacity planning
purposes, under median water, Idaho Power expects to get 285 MW from the run-of-
river plants (see 2011 IRP, page 117).
For light loading events occurring during the nearly eight month period from mid-
October through May, the minimum output for the Hells Canyon Complex is driven by
Idaho Power's efforts to maintain flow levels suitable for Snake River fall Chinook
salmon spawning, rearing, and emergence. Idaho Power manages its operations to
provide stable flows during the approximately two month spawning period (mid-October
to mid-December) and, after spawning, maintains the Hells Canyon Complex outflows
at or above the stable spawning flow level through rearing and emergence (mid-
December through May). The spawning flow level varies from year-to-year depending
on water supply in the Snake River Basin, but, in the past, has ranged from about 8,500
cfs to 14,000 cfs. While minimum output can vary from hour-to-hour depending on
water management for the three dam complex, it is reasonable to estimate minimum
output of about 300 MW during years when spawning flows of 8,500 cfs are provided,
and about 550 MW during years when spawning flows of 14,000 cfs are provided.
Outside of the mid-October through May period, Idaho Power maintains minimum
Hells Canyon Complex outflows in compliance with downstream navigation
requirements. These requirements depend on several factors, including inflow to
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Brownlee Reservoir and Salmon River discharge, but generally Idaho Power maintains
Hells Canyon Complex outflows of 6,500 cfs or higher during this period (June to mid-
October). High Brownlee inflow conditions, particularly during the early summer, may
necessitate Hells Canyon Complex outflows substantially greater than 6,500 cfs.
Minimum output during these high flow periods is variable, and typically quite high.
During periods when Hells Canyon Complex outflows can be reduced to levels of
approximately 6,500 cis, it is reasonable to estimate minimum output levels of about
250 MW.
With respect to maximum output, Idaho Power manages the Hells Canyon
Complex such that maximum output during light loading periods is typically only
nominally higher than the minimum output obtained. Capacity during these periods is
not needed, and the flexible generators of the Hells Canyon Complex can vary their
output accordingly.
The response to this Request was prepared by M. Mark Stokes, Power Supply
Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -30 Exhibit 504
GNR-E-1 1-03
D. Reading: Simplot
Exergy, Clearwater
Page 19
REQUEST FOR PRODUCTION NO. 22: Reference the Direct Testimony of
Tessia Park, P. 24, describing conditions where the Company has sufficient base load
generation to service 1,100 MW of load.
(a)For the years 2010 and 2011, please provide the hours and days of the
year that Idaho Power's load was at or below 1,100 MW.
(b)Please provide the number of hours, days, weeks, or months in advance
that Idaho Power can accurately predict that reaching loads this low will occur.
(c)For each such occurrence, please provide the maximum load within the 7
days following the light loading event.
RESPONSE TO REQUEST FOR PRODUCTION NO. 22:
(a)There were 89 hours in the years 2010 and 2011 where the Idaho Power
system load was 1100 MW or less (data from P1 Series AGC_TOTALL). Idaho Power
experienced load of 1100 MW or less in the months of April, May, June, October, and
November of 2010 and in the months of April, May, and October of 2011. Table 22.1
provided on the non-confidential CD lists the hours when the system load was 1100 MW
or less during the years 2010 and 2011.
(b)Because the term "accurately predict" is subject to a number of
interpretations and is not clearly defined in this Request, Idaho Power is unable to
provide the requested information.
(c)Table 22.2 provided on the non-confidential CD lists the Idaho Power
system load for every hour in the months of 2010 and 2011 where there was at least
one hour during the month when the system load was 1100 MW or less (data from Pt
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY 31 Exhibit 504
GNR-E-1 1-03
D. Reading: Simplot
Exergy, Clearwater
Page 20
Series AGC_TOTALL). June 2011 data is included to meet the requirements specified
in question 22(c) of this Request.
The response to this Request was prepared by Thomas A Noll, Ph.D., Senior
Planning Analyst, Idaho Power Company, in consultation with Donovan E. Walker, Lead
Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -32 Exhibit 504
GNR-E-1 1-03
D. Reading: Simplot
Exergy, Clearwater
Page 21
Table 22.1
iMaV z IN 4ad
20101 41 1814/18/20101 31 4/18/2010 2:00:00 AM 1094
120101 41 1814/18/20101 41 4/18/2010 3:00:00 AM1 1087
120101 41 181 4/18/20101 51 4/18/2010 4:00:00 AM 1095
120101 4 19F4/19/20101 21 4/19/2010 1:00:00 AM 1086
20101 41 1914/19/20101 31 4/19/2010 2:00:00 AM 1072
120101 4T191 4/19/2010 41 4/19/2010 3:00:00 AMJ 1085
120101 5 31 1 5/31/20101 2 5/31/2010 1:00:00 AMT 1073
120101 51 311 5/31/20101 31 5/31/2010 2:00:00 AMT 1040
120101 51 311 5/31/20101 41 5/31/2010 3:00:00 AM 1033
120101 51 311 5/31/2010 1 51 5/31/20104:00:00AM 1035
120101 51 31 5/31/20101 61 5/31/20105:00:00AM 1063
120101 51 31 5/31/2010 1 I 5/31/2010 6:00:00 AM 1 1094
120101 61 61 6/6/20101 51 6/6/20104:00:00AMI 1097
120101 61 7! 6/7/20101 31 6/7/20102:00:00AMI 1084
120101 61 71 6/7/20101 41 6/7/2010 3:00:00 AMI 1074
120101 61 71 6/7/20101 5 6/7/20104:00:00AM 1091
120101 101 91 10/9/20101 31 10/9/2010 2:00:00 AM 1082
120101 101 91 10/9/2010 10/9/2010 3:00:00 AM1 1072
120101 101 91 10/9/20101 51 10/9/20104:00:00AM1 1074
120101 101 10110/10/20101 3110/10/2010 2:00:00 AM 1 1095
120101 101 10l10/10/20101 4110/10/2010 3:00:00 AM 1 1086
120101 101 10 110/10/2010 1 5110/10/20104:00:00 AM 1 1092
120101 101 11 110/11/2010 1 3110/11/2010 2:00:00 AM 1 1085
120101 10 1 11 l10/11/2010 ! 4110/11/2010 3:00:00 AM 1084
120101 101 11I10/11/2010 1 5110/11/2010 4:00:00 AM 1099
120101 101 17110/17/2010 1 3110/17/2010 2:00:00 AM 1 1100
120101 101 17 110/17/2010 1 5110/17/2010 4:00:00 AM 1095
120101 iol 24 110/24/20101 4110/24/2010 3:00:00 AM! 1097
120101 111 71 11/7/20101 21 11/7/2010 1:00:00 AM 1071
120101 ill 71 11/7/2010 31 11/7/2010 2:00:00 AM 1067
120101 11 7 11/7/2010 ! I 11/7/2010 3:00:00 AM 1072
12010 1 111 71 11/7/20101 I 11/7/2010 4:00:00 AM 1087
4 1 1 4/1/20111 31 4/1/20112:00:00 AM 1089
120111 41 11 4/1/2011 41 4/1/20113:00:00 AM 1089
41 21 4/2/2011 21 4/2/20111:00:00 AM 1072
120111 41 2 4/2/20111 I 4/2/20112:00:00 AM 1060
Exhibit 504
GNR-E-1 1-03
D. Reading: Simplot
Exergy, Clearwater
Page 22
1ith4Day D ThdH
2011( 4j 21 4/2/20111 41 4/2/20113:00:00AMI 1051
111 41 21 4/2/20111 51 4/2/20114:00:00 AM 1054
l 21 4/2/2011 61 4/2/20115:00:00 AMI 1085
l 171 4/17/20111 21 4/17/20111:00:00 AM 1088
111 4 1 1 4/17/2011 31 4/17/20112:00:00 AMT 1081
120111 41 171 4/17/2011 41 4/17/20113:00:00 AM 1082
r 1 4/17/2011 1 1 4/17/20114:00:00 AM 1084
l 181 4/1812011 1 21 4/18/20111:00:00 AM 1084
l 181 4/18/2011 1 31 4/18/20112:00:00 AM 1077 111 41 181 4/18/2011 1 41 4/18/20113:00:00 AM 1082
41 24 4/24/20111 ii 4/25/20111 1094
511 41 25 4/25/2011 21 4/25/20111:00:00 AM 1065
41 25 4/25/2011 I 4/25/20112:00:00 AM 1064
41 25 4/25/2011 41 4/25/20113:00:00 AM 1074
51 31 5/31/2011 31 5/31/20112:00:00 AM 1091
111 51 311 5/31/2011 I 5/31/20113:00:00 AMI 1093
120111 101 lollo/lo/2o111 2110/10/20111:00:OOAMI 1088
i120111 101 10 110/10/2011 3110/10/20112:00:00 AM1 1085
511 10 1 10110/10/20111 4110/10/20113:00:00 AM 1095
120111 lOj 14110/14/20111 2110/14/20111:00:00 AM 1097
120111 101 14110/14/20111 3110/14/20112.00-.00 AM 1086
120111 iol 14110/14/20111 4110/14/20113:00:00 AM 1 1086
101 1510/15/2011J 2110/15/20111:00:00 AM 1070
101 15110/15/2011 3110/15/20112:00:00 AM 1 1051
101 15110/15/2011 4110/15/20113:00:00 AM 1 1040
011 10 1 15110/15/2011 5110/15/20114:00:00 AM 1 1054
120111 101 15110/15/20111 6110/15/20115:00:00 AM 1 1086
120111 101 16j10/16/2011 2110/16/20111:00:00 AM 1 1070
511 101 16110/16/20111 3110/16/20112:00:00 AM 1 1050
1311 10 16110/16/20111 4110/16/20113:00:00 AM 1 1043
120111 101 16110/16/20111 5110/16/20114:00:00 AM 1 1048
120111 101 16110/16/20111 6110/16/20115:00:00 AM 1 1069
120111 101 16 110/16/2011T ii 10/17/20111 1067
120111 101 17110/17/2011 2110/17/20111:00:00 AM 1 1059
120111 101 17110/17/2011 3110/17/20112:00:00 AM 1 1052
120111 101 17110/17/20111 4110/17/20113:00:00 AM 1049
120111 101 17110/17/20111 5110/17/20114:00:00 AM 1 1082
120111 101 19110/19/20111 3110/19/20112:00:00 AM 1096
Exhibit 504
GNR-E-1 1-03
D. Reading: Simplot
Exergy, Clearwater
Page 23
2011 1 101 19 110/19/2011 1 4110/19/20113:00:00 AM 1100
JiE 101 21110/21/2011 3110/21/20112:00:00 AM 1 1095
120111 10 21110/21/20111 4110/21/20113:00:00 AM 1091
120111 101 22110/22/20111 3110/22/20112:00:00 AM 1090
611 101 22110/22/20111 4110/22/20113:00:00 AM 1086
120111 101 22 110/22/20111 5110/22/2011 4:00:00 AM 1 1099
120111 101 23 110/23/2011 1 2110/23/2011 1:00:00 AM 1 1100
120111 101 23110/23/20111 3110/23/20112:00:00 AM 1087
11 101 23110/23/20111 4110/23/20113:00:00 AM 1 1082
10[ 23FIO/23/i011I 5110/23/20114:00:00 AM I 1090
120111 iol 23 110/23/2011 1 1 10/24/2011J 1099
10 24j10/24/2011 2110/24/20111:00:00 AM 1071
101 24110/24/2011 3110/24/20112:00:00 AMT 1058
111 1 10 1 24110/24/2011 4110/24/20113:00:00 AM 1 1059
120111 101 24110/24/20111 5110/24/20114:00:00 AM 1 1087
Exhibit 504
GNR-E-1 1-03
D. Reading: Simplot
Exergy, Clearwater
Page 24
Zp
I - C uj
Table 22.2 (2010 Data)
ki 2::.j3 4• ________________
4/1/2010112851126011261 1278 1324 1419 11597 11738 17371172111694 1662 1630 1598 156611541115411153111527 1521]1607116171152711417
4/2/201011352113311132811344113831462116251174511744 17221169411657116211159715971162111659168816511167211691 1634 1 1531 11424
4/4/2010 11284 11251 1124711253 11277 11325 11404 11498 11551 11555 11508 11457 11420 11375 11327 11291 11285 11300 11333 11381 11460 11449 1 1348 11228
160411589 J1544 J1502 114561141311381113611368113851142611501114971142811343
1 4/6/2010 11276 11252 11249 11263 11302 11405 11612 11755 11711 11657 1161711581 j1541 1i1484I1459 1448 11453 11453 11465 11555 11565 11448 11311
4/5/2010 11163 1I1139 J1154 11190 11289 11501 11670 11670 11654 11645 11627 11588 11562 11531 11516 11507 11520 11538 11538 11601 11583 11463 11339
4/7/2010112201124111242 J1261 11308114141163011762 J1707 11633 11554 11512 114861449 1399 11391 11373 11369 11371 11384 11481 11513 11399 11268
4/8/20101120211180111791119311227 [il1531 11661116461161311590115841153611504114821147311471 Fij1483 1150211596116121150211382
4/10/2010 11310 11293 1129711310 11335 [1 11491 11581 J1617 J1610 11583 11532 11478 11431 11385 1136111351 11344113481135411417 11422 11343 11256
4/9/20101131611298113011132011363 1iil1675 11808 11779 11716 11662 11603 115501504 11480 11524 11457 11369
4/11/20101119311157111451114511158 [iil1266 113551143011466114571142211394113611134811343 1349137513811139811457144313341210
4/12/201011138111131110511112111531124911450115941160611607 Ii611 11607 11576 11558 11533 1151211504 114961149011501 11553 11556 11434 11308
4/13/2010 11245 11227 11231 11244 11286 11389 11593 11719 11692 11648 11612 J157911549 11526 11504 11483 11468 11461 1145711455 11515 1154811432 11303
4/14/2010 11235 112141121411230 11270 11373 11585 1170011646 11587 11546 11521 11486 11470 11451 11433 11424 11421 1141811412 11473 11515 11404 11278

[4/15/2010 11205 11180 11179 11188 11220 11315 11524 11644 11617 Pi1549 11525 11491 1465 11454 11446 11440 1143011422 11493 11518 11401 11264

4/16/20101118511153111421114511172 j1256 11438115581157311557115401152211495 iil1484 1147711471 146514511462114911479 13881280
4/17/2010f1197 11146 1 112011111 11121 1115811236 11305 11381 11423 11421 11406 11380 11363 11346 11339 11346 11366 1136611357 11403 11432 1134611236
4/18/2010 11155 11110 1109411087 11095 1112511184 11250 11320 11353 1355 J1346 113431133211325113241134411375113911139511438 [iii9 1214
4/19/2010 11128 11086 11072 11085 11115 11203 11398 11524 1154011545 115461154711550 1iI1561 115691157711586115901157911613116251148411324
4/20/2010 11228 11187 11163 11156 11171 112481141811530 11552 1156611584 Jiss 115971160911616116141159911593116011158811598115631141711284
4/21/201011208 iiiI1155 11143 J1161 1 1233 1140711544 11576 11594 11558 11568 11551 11553 11542 11521 11517 11524 11517 11502 11537 11545 1142911300
F4/22/2010112241118011162111641118911271114541158211607TI6171161311611115901157411542115251153211.537115291151611537115561143811305
4/23/20101123011199111851119311218 Fiól1496 11609 11598 11576 11555 1152411484 11462 11430 11414 11396 11382 11362 11344 11379 11443 11379 11278
4/24/2010 11209 liiI1 156 11157 11173 11215 11293 11357 11405 1416 1 i3%11 i9 134411329 11321113211133311335113301136811418 1353 1259
4/25/2010 11194 11167 1115611160 11173 11217 11284 f1349 11414 1144011436 11412 11395 11369 1134011327 11329 11347 11357 11370 11428 11469 11370 11249
4/26/2010J1181 111591115711173112101131111507116151161711598115751156411541 ft115151 1505 115011502 11491 11534 11558 11429 11288
4/27/20101120111155111391113711158 iiI1404 11530 11557 11572 11580 1157411566 115601153711530 J1529 115501154411534 J1570 115471143311297
4/28/201011239 1121411203 11205 11236133411532116531166311645116561162711593115701155011540 11537 J1544 1546 1552 11578 11612 1150411371
Q CD co r
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cat j 4JI i;2
4/29/20101130411286112831129111326 1421 161611734 1733 171711712117041167011634116021159011587 1597 1596 1591 16331165011533 1397
4/30/201011319112871127811283113121395115861171311724 ho9 1169211662116191159411558115301151615051 n/aJ n/al n/a n/al n/a 11391
5/1/2010 11318 12831127011275112911134211415114891155711596116031158511540 114991478114601145211467114741146311505 154411474 11384
5/2/20101131411250112321123111244112801133411383114331146111469 114461142311391113601134711346113651137511388114351149611406 11271
I 5/3/2010 11193 11158 11148 11151 11185 1128411483 11616 1165311658116651167511659 j1633 11615115961159111589115751156511588116201151511386
— 1553]14151
5/5/2010 11343 11318 11312 11315 11334
5/6/201011428114031138211387114211152211718118071178211748
F11605 117211174011744117181171111691116641165911650
117271171111681116501161911599115901158711573115571157211620
1165611639116311162411668117261160911506
[i542 11431
5/7/201011370113471134911368114101150711685117631174011726 117201170011662116411162611610116061159811577115581156811628 157011475
5/8/20101140011368113541135111367114091147411533116211168411692116591161511590115751157111572115771157311 565 11574 11629 157811482
5/9/201011406 liI1337 1133711343 1il1429 1149311575 1i1599 1156411538 [150811483114731147811494114991151711545115911151411394
5/10/2010 11322 ii1276 1128511321114131158911712117461177411797118151181111786 11767117481175611775117501170611707117311161811493
5/12/2010113151128111266112721129811381115511165311647116201163411 621 11605F15971580 115701156811565 1155411546115501160211512 1379
5/13/201011294112641125911272112961138111548116441164111629 ' 11621116141160311600115981159911598115961159011578 11581 11638 11561 11420
5/14/2010 11327 11284 11270 11269 11289 11364 11509 11613 11635 116441166311666116571165016481165211660 11654116431161611607116521159311461
5/15/201011369113141129311290112951132611373 1144011520115641159511604116001160111608116201164711676 116781166611648116791161211501
5/16/2010114071134611315112991129311309113121137511459 1520 1155611566115861160611622116411166311692116981169111684 11716 11621 11477
5/17/201011383113401130911297112971136211509116451171311757 1180711834118571187211886119041191011909 J1901 1187311857118381171411562
5/18/2010 11469 11413 11387 11378 11381 1440115721168811721117451176711765117621175111729 117161171311703116961169011695117301164511506
5/19/2010f1422 1136711345113381135111422115611167211713 11703117431175311746117531176311766117711176611767 11762 1 1765 11816 11713 11544
5/20/201011437113791133711329113361140311551116591169511714 1173011731117161170211687116761167111659116431163911654 117091164211503
5/21/2010 11410 11365 1134011337 11354 1142611580 1172211772 11789 1178711781117541173011702 p1681 11669 iüiI1641 1163311646116831162211507
5/22/20101142511383113591134111345113791143111516 116171167711708117141170211686116711165811650116381162011598 11588 1160111532 11416
5/23/201011333112991128511281112861131111349114111147511516 115221149511457114201138911364113781139811402114051140711450 1139711278
I 5/24/201011200111761116411178112141130911482116311167811688 1691168816621635116111158411567 11567115631154811548116011154011407
I 5/25/20101131911279
I 5/26/20101139711351113251131011325113911154111682
J1261 1126011284113771152811655116891170111706117041169411688
J1734 11737 117691175011740 1173311724117101170211704117001169311703117431165811511
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1 5/27/201011413 11361 113301 1318 11337 1140911554 1166911726 I1761 1177711780117701174811725116951167711659 11638 11635 11653 11671 11572 11417
1 5/28/201011337 11296 1127011261 11276 1133911469 1159211658 11663 11657116471162211590115681154711531115151149411464 J1464 115081146711365
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5/30/201011174 -- 1 1.30 11112 11105 11111 11144 1168 11214 11267 1301 1313 11305 11299 11283 f1273 11275 1293 11293 1128411277 11326 1309 11213
6/1/201011183 [iii]1118 11109 11126 11190 11329 11473 11560 11597 11622 11630 11629 11630 1623 116091595 11590 11578 11571 115701595 11518 11371
[6/2/2010 112681121611 183 j1169 1117611237136311497115791160711665116811167711676 168111669116591165511664116601164716721157511420
6/3/201011324112781124511225112251128311402115341161411650 11670 11684 11678 11668 11663 11655 11651 11649 11644 11641 11640 11664 11587 11446
6/4/201011345 11294 11259 11238 11250 11308 11411 11540 11632 11678 11704 11710 11684 11672 11648 11609 11584 11580 11560 11530 11520 11541 11483 11368
6/5/20101127511223111761115611147111721120311264113601142211451 J1470 11466 1i 11453 11452 11456 11465 11463 11456 11465 11499 11461 11343
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__________________________________________________________________________________
1607116121160111591 11593 S11556 149711332
11102 11112 11168 11264 11384 11472 1i1562 J1589 J1601 F16171163111648 1659 [1664 16491162611617 Fi1567 11405
1 6/9/20101129711229111871116811174112271133111452 ii539 1ii1648 1168411683116911169711692 J1702 117171171911712116801168411632 J1466
6/10/201011338 11263 11221 11206 11214 11264 11363 11500 11610 11670 11699 11707 11700 11691 11677 11663 11650 116401163511619116121164311620 f1475
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F 6/12/20101143911381113451131511305 (i 3 J1.439 1539 11615 116621167511670116651166511656116721170311714117091169611703 11669 11545
1 6/13/2010 11440 11356 I 13071128311276 1iiii1343 11441 11512 11565 11593 11617 11628 11to 11659 11699 11742 11763 11762 11746 11747 11702 11530
1 6/14/201011395 11322 11283 11268 11280 11344 11439 11595 11740 11835 190011949 j1992 I12084 12119 12138 12173 12197 12179 12131 12100 12009 11821
F 6/15/2010 11670 11580 11519 11485 11478 11518 11600 11752 11869 11938 119811200212003120201203012024120241203912045120331199911996 11931 11762
1 6/16/201011640 11560 1151411485 11485 11538 11633 11759 11857 11896 11945 11950 11952 iI1925 11902 11872 11854 11841 11808 11800 11819 11767 11621
1 6/17/2010115281148211453 J1445 11458 J1518 1163311762118401188911907119201192311924119101190411881 1865187418721186018711186111720
1 6/18/201011602115331149111473114841154311638117621186411919 J1943 11942 f1943 1195611962119771198712001120071198811965119741193311795
6/19/20101167411589115461151811504 iiJ1531 1162911744 11826 11893 11929 11952 11969 11993 12009 12043 12062 12049 12043 12006 Ii1956 11805
6/20/20101167411584 11526 1148511466 11476 11471 1153211636 11715 1177011806 J1822 1815 lii]ii0 180618 i1793 11775 11745 ftiI1739 J1610
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6/22/201011710 11620 11570 1154011540 11592 11683 1182411929 11995 12043 1206812087 12111 12126 12145 12149 12176 12200 12189 12149 12144 12082 Iii
6/23/2010 11747 11659 1605 11578 11573 1618 11695 1183811958 12020 12108 12158 12206 I2323 123691240912448124521242312377 J2349 12268 f2067
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6/25/201011950 11858 11785 1174211725 11754 118311197312098121831225812316 j2362 1234612346123231231612305122721221312165121551209111952
6126/201011818 1iiI1671 1163211611 J1619 11634117421187111974120501209712135 1218012215122611229912328123481234112294122341217912008
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Ui C) -
;2i 4J
6/28/201011806 1705 164511620 11622 166511751119231207612200123051241812514]26121270712787 284412896 292212872 2762 2649 24892295
6/29/201012128 2035 1940 11874 11846 118751953 I20 223212343 Ii12478 2543 258612612 J2571 1249125302511125011253725231240212209
6/30/2010 2043 1925 11824 11767 11749 1801 1903 12029 2153122131230012357 J2410 2452 2502 12545 12577 12580 12589 12578 12532 2471 12378 12170
10/ 1/2010 1415 1360
10/2/201011414113521131111282112811130411358
1329 11313 11320 i01524i.641
J1422
1652 11676 117 12 11740 11778
1553 11600 11635 11667 11707 11767 11836 11908 11951
1837 11887 11947 11995 12011 11967
11918 11871 11831
11905 j1876
1731 11609
117731164411512
11478
10/3/2010 11385 1324 11287 11266 11260 11272 1129611336 1393 1477 1521 11552 11601 11654 11715 11767 11786 1779 1749 1175411732 1iI1504l1371
10/4/2010 11294 11253 11230 11225 11242 11312 11478 f1621 1635116431166911674116661166711655116471163611629 11645 11687 11682 116001464 11328
10/5/2010 11246 11206 11186 11173 11189 11256 11419 11559115721157611579 J1575 11569 11561 1154911555 11557 11561 11569 1163111655 11577 11441 11309
10/6/20101123011196111791117111187112541142411541 11544 1546 156 1 11565 11555 1553 11551 11543 11538 1154311544 11589 11601 11536 11417 11300
10/7/2010 11224 11183 11162 11155 11171 1123511356 11447 11478 11518 11540 11547 11535 11 544 11555 11557 11558 1543 11539 1158011574 11502 11394 11260
10/8/2010 11184 11139 11140 11142 11155 1121511335 11452 11492 11532 11547 11540 11517 1149711476 j1464 1457145311446149011467 1397 131911213
10/9/2010 1140 1106 11082 1107211074 j1145 112291119911350114481147411463114281140211381 J1377 1379 1398 11402 11459 11462 11417 1335 11236
110/10/20101116511120 1095 11086 11092 11113 11155 11220 11272 11320113441136211378 iii1389 11409 11440 11475 116 1155011555 11471 13481226
110/11/2010 1149 11106 11085 1108411099 11165 1131811457 11472 1490 11505 11507 11496 11486 11465 11450 11441 1447 1460 11533 11541 J1471 134911227
10/12/2010 f1166 11147 11137 11139 11164 12451143511597115961157311547(1525115051148411460114451442 i1451 11542 11550 I1i4 1363 11249
I:LO/13/201011183111531113-9fll4511173112591145611611116011157211545115231149911490114791148211481114761148011557 11566 1493 1367 11244
110/14/2010 (1183(1165(1157(1166(1192(1277(1469(1613116001157611555 (153311509114991149711493114951149711493(1559 1561 1488 1371(1265
110/15/201011189111561113711131111 481 -1221 11382 (15 24 (1538 153811537(152211501(1489(1479(14781147611470 11455 1504 147811429 1350f 1257
110/16/201011186 iii(1134 (1128 11135 11161 112211130411372 FiI1432 11419 11402 (1387(1381 11376 11380 11396 1414 1464 1444 1393(1314(1230
110/17/2010 11162 (1125 11100 (1106 11095 1i1178 1122911303113531136911362 113681135211344113241133211373114031148511478114061129711203
10/18/2010 11157 (1138 (1129 (1141 (1177 1266 (1458 11596 11590 11570 (1550 (1536(1511 11500 I10 1147111473 1478 (1492 11571 (1562 11489 (1367 (1249
110/19/201011182111621115311162111921128411480116361162111583 15611537 1509 1497 (1485114801147511477 1489 (1566 (1557 (1488 (1370 11258
110/20/201011190111601115511162111961129211484116361162111576 115521152511494 1490114811147411476 1474 14851155811533114841135911238
110/21/201011173111461114311150111831127511474116271162111575 15611153711493 11485114851147711466 (1459 (1476 (1552 (1535 (1463 (1347 (1231
10/22/2010 11164 (1130 (1118 (1116(1143 11218 1387 11532 (1551(1537 (1517(1497 11472 11456114401142911420 11413114181147711450114031132911239
(10/23/2010111711113911125(1118(1127(116311227(1315(1397 (1453 (1477 (1479 (1463(1433(1398(1378(1364(1381(1407(145911434113871131511231
(10/25/2010(116711143 (i 138(1139(1172(12641146611590(1528(152511521(1564(1577(155511524 (1506(150711531(1587 p1649 (1628(1562 (143111318
110/26/2010(1258(12341121411217(124711340(1517 (16431165911647(163011608(1586(156811549(1543 (15521158511634(167911653(158811466(1342
(10/27/2010(127711253(1239(1248(1271(136211555(1711(170311647 (1601(1564 (1526 (1497 (1472 (1456(1455 (1482 11561 (1639(1622 (1559 (1436 (1322
T1 OD
CD O CD
4. 0
4;I ;47k8 Io *1I*I 2W!II15 $1 2
110/28/20101125811226112191123011256113401152311676116811637 160911579 1534 150311467 1457 1450 1461 1512(1593(1567 1504 1400 1305
10/29/2010(1241(1239(1192(1195(1223 1296 114561159411625 (1609 (1587(1542(1492 454 11420 11390 (1391 (1393 145411420113901139111393114221148211467114251135311275 ' (1422 (1482 (1467 (1425 (1353 (1275
110/30/2010(1220 11189 (1179 (1182 (1194 (1231(1298 (1401 (1494 (1547 11554 (1514 (1466 11427 11385 (136711377 11384 11424 (145511434 11394 11335 1 1263
110/31/2010 (1199 (1157(1140(1132 (1133 (1156(1210(1289(1371 1418 I16 l1431 11428 (14111138111351(1358 (1369 (1389(1428(1424 1140411314(1208
11/1/2010 (1148 (1122 11118 (1131 (1160 11248 (144611610(1616 11579 (1551 (1517 (1477 11449 11422 11407 11401 11414 11475 11556 11532 11465 11349 11234
11/3/2010(1155(1128 fti]i129 1159 1252]1445 11607 11617 1567(1525(149711463114461142811417114121141711482115451152211458 1342 (1226
11/4/2010(1163 (1128 (1113 (1115 (1150 (1239 (1423 (1582 (1604 ij1529 1150011455 1434(1410(1393(1380(1391 (145311518(1493(1429(1318(1209
11/5/201011143 (liio 1110211107111361122011394(1550115831155411519(147911430 [i]1373 (1360(13451356 (1426(1477 (1446 (1399(1326 11235
11/6/2010 11169 (1134 (1119 11118 1[iij1247 (1345 11432 11466 11465 11443 1 1392 11341113021129011279 iii 11.32i405[iii(1275 (1193
11/7/ 2010 (1131 (1071(1067 (1072 (1087 (1131 11201 (1292 (13651140411417(141911420(1418(1406(1415(1460(1545 (1577 (1537(1490 (1412 (1308 (1206
11/8/2010(1153 (1139 (1131 (114611194(1308(152211664(1662(1645(1625(1608 (1580 1561 (1541(1540(1562 1679(1761(1727(1Gm (ls90 (1461(1350
11/9/2010 11291 (1290 1289(1304(1362(1476(1687(1799(175411687 I16l1601 [1547 (1520 (1497(1501(1552 (1693 (1767(1735 (1691(1605(1471(1360
1 1/10/2010 1 3001272 1261(1276(1306140911603 (1738 11725 11707 (1690 (1665 11630 (1595 (1570 (1578 (1613 11739 (1779 11746(1706 (1620(1500 (1391
11/11/2010(1341(1317 jiii(1326 (1369(146811658(178611764 [i(1680 (1637(1582(1565(1554 (154511568(1682(1759(1743(1712(1635(1518(1413
11/12/2010 (1353 (1319 11305 (1301(1340 (1432 (1603 (1732(1726 (1703 (1664(1603(1555(1528 []1486 (1509 (1628(1691(1660(1629 (1587 (1511(1428
11/13/2010J1369 (1342 (1338(1341 (1367(1420 (1514(1608 (1673 ii1696 11665 (1631(1592 1572 (1561(1592 (1687(1711(1671 (1627 (1564 (1479 (1390
11/14/2010 (1330 (1294(1271 (1273 (1284 (1321 [i9 (1461 (1534 (1581 (1588(1578 (1573 1541 (1523 (1522(1556(1665 (1703 (1673(1626(1542(1425(1319
11/15/2010 (1263 (1239 (1227 (1240 (1278 (1379 1577(1702 (1664 (1625 (1599 (1574(1528 1509 (1500(1513(1550 i(17O2 11663(161811532(1408(1292
11/16/2010 (1227 1204 (1 194(1195(1237(1340(1530(1665(164111622(1615(1588(1566 11540(1526(1514(1534(1669 (17is (1730(1696(1627(1507(1402
111/17/2010(1341 (1319 (1310 (1319 (1355(1448 (1632 (1766 (1740 (1678 (1673(1650(1621(1603(1596(1600 (164311748(1772(1738(1697(1620(1478(1364
111/18/20101129511262112441124111267 1356 115341167411661 (1644(1629 11613 (1591 11579(1557(156711613 (1720(1749(1725 1685 (1606(1490(1377
111/19/201011312 (1291(1285 (1292 (1326 (1414(1593(1733 (1739 (1729 (1723(1702(1676 (]1651 (1655(1690(1770(1774(1727(1669(1621(1544(1455
111/20/20101 1375 (1335 (1315 (1308 11319 (1370 (1443 (1538 (1622 (1672 (1689(1664(1616(1580(1557(1557(1596(1720(1761(1728 (1692(1641(1568(1489
11/21/2010(1426 i(1389 (1392(1409(1444(1510(1606(1682(1715(1722 (1724(1721(1711(1693(1692(1720(1837(1862(1828(1789(1721(1608 (1491
111/22/2010114271140511397114M 1144611538117011181811817118091179711799117821177611774117891183511943119741194311904118221168411549
111/23/201011470 [(1433 (1439(1478 1i(1707 (1843(1870(1888(1888(1861(1843 fi (1851 (1867(1919(2055(2115(2089(2046(1980(1876(1766
11/24/2010(1698(1681 (1666 (1682 (173011814 (19 (2098 (2146(2126(2078(2034(1987(1955(1889(1898(1957 ((2139 (2120(2088 (ó(i9Ti(i847
11/25/2010 (1786 (1751(1754 (1764(1790 (1839 (1912 (1999 (2068 (2086 (2068(2027(1935(1825(1750(1723(1745 JiI]1875 (1876(184911814(1741(1661
11/26/2010 (1608 11595 (1593 (1601(1634(1697(1775(1854(1880(1858(1823(1792(1760(1738(1724 (1729(1779(191511942(1915(1871(1810(1734(1656
1 5' 8'II 9 IO t$Ti3 1i9 i2I 22
111/27/20101159211540 151 P1501 11504 11539 11598 11669 1 1739 11810 11832 11820 11796 175711723r1719 1766 1868 1886 185011810 1756 166911578
111/28/2010115141147911469 11479 11490 11538 1161411707 11773 11794 1772 11739 11716 11696 11682 11693 11745 1903 1965119471190718221170911603
111/29/201011550115411155111580 11639 1749 11946120921206412001 11944 11882 1181911768 11737 1173411793 11987 12082 1207 9 12061 119801 1848 11728
111/30/2010 11672 1165411654 11666 11709 11806 11992 12121 1208412049 120141197511949119281191711934119821209512118 12084 12035 11941 11803 11668
CD
Table 22.2 Continued (2011 data)
CD DQ CD 0- <
CD
-•.Lu
CD • 0
bate 3.; :ji :5.•j I 11 .iI 3T14r
4/1/2011 11251110411089 1089 1115]11911134911482 14861465 1454 1431J1403 1387 11372 11351 113421343 11333 11331 114021393 1311 11189
4/2/20111129011072110601105111054 1085 114712301323 11430 114781471 J145 11426 J1399 113861139414101409114231150715191144011348
4/3/20111125011261112441125011271 1iIii]1384I147O 115231156311539115001147311430113841135211351 [iiI1376 113991151911542144111317
4/4/20111119211240112451125111286 [iil1590I1721 11713116891166211628115701155211521 J1495 1487115011151711520 j1576 1140411267
4/5/20111125911165111511115411182 1iiJ1459 11605 1 1611 11620 11627 11611 11578 11543 11511 11491 11480 1482 1 147811476 11559 11569 11455 11326 T 4/6/2011 11271 11238 11243 11263 11307 11413 11622 11745 11717 11677 116321159111557 fiiJiso& 114801147811498115341155911610115901146311338
4/7/2011113051124511233 J1242 J1282 1370157517211715169716691621115751547152211500 J1481 11486 114821150511592 11595 116 11371
4/8/2011113011128411282112941133611435 1 1627 11753 1736 {iii]1683 11645115941155211513 J1490 11481 1477 1462 11468 11540 11547 11476 11372
4/9/2011 J1279 1268 fiij1252 11267 [iiJ1397 11488 J1559 116071160511567 Jisio 11454114061137911376113831137411375114591149211427 Fii
4/10/20111116311249112401124611267 iiiI1383 1454 11507 15091148311444 J1412 11374 11342 1132211318 11342 1364 J1375 1144411459 J1353 11232
I __________________ ________________________
4/12/2011 11165 1174 1182 11196 11235 1349 11560 J1676 11646 11592 [iiij1499 11463 11436 11413 11386 11368 [i1355 11360 11441 11472 11363 11236
4/13/2011 112681143 11142 11153 11191 11285 1148811618 11607 11591 115801156611542 11530 1508 11500 11503 1i1529 11497 11556 11561 11451 (1332
1 4/14/20111127111248112491126611308114161163911750 [1704(i i(1617 1157511540 [iij1478 11455 11439 11435 11439 1145011538 11561 11451 11333
1 4/16/2011(1135 1168 Ii 150 1146 (1157 1198 11275 (1348 (1410 1143311423113941135811327 1301 (1289 11288 (1309 (1316 1133611382 1377 11302 j1210
4/17/2011 11114 Fi1081 11082110841110611169112441132411362113651134611334 1iiI1288 (12761128711322 i341 1135811424114181131411189
4/18/2011112661108411077110821111411209[140611546115701158711586(15711154411509114751144511432 Iii1439I1444l1518I1551l1444I1322
[4/19/201111253112471125111262113081141711634117301167511629 (159511555115151148611456114311141411410114061141211496 [(1446 (1318
4/20/20111121411234112411125511296 [ii]1600 11705 11687 11653 11621 11576 11545 11520 11500 11493 11502 11509 11508 11499 11532 11541 11424 11292
4/21/2011 11296 11183 11175 11173 (1202 11294 11481 11598 11610 11611 11603 11605 11561 11544 (1514 11492 11479 11474 11464 11459 11538 11586 11480 11365
4/22/2011 11218 11266 11264 11276 11313 1 1412 11611 11702 11662 1159711548(1504 114541141811383113571133611323113011129111363114351138011282
4/23/2011(114711195111961120811237 1il1381 (1453(1491(1489(143711385 (1338 11297 11268 11248 11242 11252 11249 11243 11300 11372 11318 11225
4/24/2011 (1094 (1114 (1111 11122 11143 11191 11268 11338 11406 11422 1137911335 11320 1283(12371120711189111971121811256(132211355 (1157
4/25/201111220110651106411074111091120711400115281155911573115811157311544115331151511476 (147511478114711147111538115331141811287
4/26/2011(1256(1207(1220(1231(1271(1375 11585 11686 11664 (1633 (1613 (1599 11567 (1541 (1501 (1493 (1480 (1471 114721145411506 1562 11457 11327
4/27/2011 11165 [iI1241 (1255(1294(1401(1607(168311631116091156611534(1508 i(1467 (1445(1433(1424(1414(1405(1456 15101139311261
4/28/2011 (1327 1136 1112911133 11160 11248 11441 11564 (1574 156411572115821157711566(1554(1552(1551 (i(1552 (1549(15801162511519(1396
pct11
(D CD
On
<
C (/D
CD —
Dat I 3 i 4 71 8 12 13 14i 15 i6 11 18 1.9 2OI 2& 221 231 24
4/29/201111301 1301 1294 11303 133511431 16i11740 1737 1722 11706 1666 11621 158211541 1514 1496 1491 1477 1463 1505 154911475 1376
I 4/30/2011112521275112651127211296113561143011481 1513 15351152311495114491408113791136111357136711361113671140011472 J1417 J1320
5/1/2011 11175 11226 11226 11231 11247 Fi1365 114141145011463114491141711392113591133411318113201134011350 1135411399114701138411251
5/3/2011113111122711219
5/2/2011 11260 11154 11155 11177 11221 11330 11538 11635 11624
p1223 11261 11364 11563 11679 11692 1675 11659 11640 11608
162111613115951157311562115531153411523 115M11568 1156611549
F1534115531156011582
11545115261152711568
1590
iij1528
147511341
11391
[_5/4/2011113111127711271112781131111414116141170411695 ftT1657 11619 11610 1158811576 11559 11550 11549 11550 11541 11570 11645 11535 11393
I 5/5/2011113321127711258112641130011409115961169111700 116921168411676116581165111650116431164411632 11623 11611 11634 11685 11582 11432
5/6/2011 11365 11285 11259112501126411343 11505 11621 11672 1688 11689116781165911658 11M7 116301162511617116041159711626116481157311456
5/7/20111129111314112901127511281 [ii1366 1142711515115691157811569115511152311502 114821147911487114891148911522115531148311376
5/8/2011112281124411216 J1201 11197 1121711260 11327 11418 11485 11509 1148911468 1143811408 11384 11380 1138911395 1140011428 11501 11427 11301
5/9/2011 11293 11195 11197 1120911249 11351 11546 11676 11703 11709 11697 11682 11654 11627 11597 11580 11576 1158011576 11560 11572 11605 11498 11370
I 5/10/201111219112671124311238 j1268 11361 1 1544 11622 11621 11589 11570 1156611543 11532 11513 11505 11500 11501 11490 1147811487 11543 11449 11309
5/11/20111125011185111731118211219113151147611557 15611158811555115551154411538115331153011535115381153811523 1535 11602 11505 11346
5/12/2011 11290 11196 111671116011177 1125811411 11513 11537 11561 11584 1159911604 11624 11632 11638 11650 1165811648 11630 1621 11667 11566 11398
I 5/14/2011 1132211312 11275 11238 11227 1125611293 11357
I 5/13/2011113731123711208111961120911275114051151511566 iJ1619
11451 11528 11555 11572 11599 11618 11635 11651 11638 11633 11611
11632116411166011677116981172211733117161167111670
11586115651157811511
11691 11608 11468
[iIi
5/15/2011 11277 11266 11221 11212 11232 11249 11303 11397 11466 11495 1150411507 11495 11483 11484 11498 1151411537 1154811568 11574 11471 11347
I 5/17/201111363113271131211312 JIL34411442116171171611735 117261171411694116761166411653116451164111638 116351163711652116811158911450
I 5/18/2011113501132411315113111133711416 J1579 11717 11745 11720 11723 11717 11691 11675 11653 11641 11634 11633 11627 1162211632 11669 11568 11437
I 5/19/201111320113051128711277112921137811534116591168711684 J1676 1166711656116441163311616116071160311597115931159511643 11569 11418
I 5/20/2011113631127011246112291124011317114551157611638 1iI1660 116631165811662116551165611653116501163911626116101164511598 11466
I 5/21/20111134511305112731124611243 127313211404150215621591160916121161316141161711621 11618116021159411592116171155111438
5/22/2011 11284 11297 1127411249 11242 11256 11272 11338 11435 11496 11523 11532 11548 Ii1525 115201153311558 j1569 1156611562116041152911375
1 5/23/201111365112371121411203112211129911452115921166311695 11713 1172011719 11715 11705 11692 11683 11690 1169011671 11678 1170 ]1606 11457
5/24/2011 1136411325 11303 11292 11316 11403 11559 11682 11703 11712 117111170311694 1i1i1648 116421163711632116331162111617116621160211456
5/25/201111394113181129711284113071139811533116511169811711 11730117211171411710117081170511704 J1702 11710117221172111726 []iii
5/26/2011 11365 11358 11335 11320 11334 11411 11558 1167611713117171171611705116841166811652 j1634 11617 Ji]issi 11572115801163411574 f1447
5/27/201111363113141129611289 j1310 11380 11511 11631 11688 11720 11730 11715 11679 11653 11651 11621 11595 11582 11593 11576 11545 11579 11542 11444
5/28/2011 fl3os 11323113031129111296 iij1373 11438 11510 11562 11567 1155011529 i 1jii84 1147911476 [3.f1487 1148011489115221147311383
CD CD
ar
• 113 18 :1i fL! hv ki2O
5/29/2011(1190(1264 1240(1230 1231 126111302 1354 1420 1457 1458(1444 1420 1384(1357 1339(1348(1348 1334(1336 1352 1393 1351 1257
5/30/2011 (1145 (1153 (1137 1128 11139 1184 1229 (1287 (1364 1i1466 1147211444140511377113621361 1373 (1376 (1372 (1379 (1434 11373 (1233
5/31/2011 (1256 (1106 (1091 11093 11124 1205 (135111486 (155715841159511594115771156511563115651154611543(1542 (1530 1536 (1572 11500 11352
6/ 1/2011(1343 11206 (1179 1116811180 (1252 1374(1493 11556 11589 fiiii(1624 11634 11625 11618 11606 11601 1602 (1601 (1591 11602 (1634 (1553 (1424
6/2/201111438 (1320 (129811285 (1294 (1371 11503 (1638 (1718 1i1773 11781 11751 11725 117001 11669 11666 11660 11656 11664 11713 11655 11532
6/3/2011(1441 (1363 (1338(1325 (1339 (1416 (1543 (1662 (1697 (1712 i712 (1718(1706 1694(1689(1686(1672 16571164711651 (1M8 116881166211542
6/4/2011 (1456 (1389 (1350 (1335 (1329 (1361 (1412 (1505 (1587 (1645 1655 11670 (1669 11670 1167411673 (1685 11704 11703 11699 11699 (1727 11691 11560
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C
LA th
C
REQUEST FOR PRODUCTION NO. 23: Reference the Direct Testimony of
Tessia Park, p. 24, describing the minimum base generation (300 MW thermal, 817 MW
hydro, and 50 MW non-intermittent PURPA) to be near 1,100 MW. Please explain why
Idaho Power could not plan for an expected light loading period coinciding with possible
excess OF generation by un-designating the network resource status of a specified
quantity of this base generation, and using its fast-ramping, remaining Hells Canyon
capacity to serve load in the event that intermittent OF generation did not occur as
predicted
RESPONSE TO REQUEST FOR PRODUCTION NO. 23: The particular network
resource that is undesignated must be used to supply energy for a sourced sale. If
Idaho Power undesignates and sells power from a baseload resource, that resource
must be able to supply the system sale. In order to sell firm resources into the market,
Idaho Power limits the amount of generation from the baseload resources to 50 percent
of that resource's available generation capacity to ensure sufficient generation exists
from that facility to supply the firm sale and to comply with Idaho Power's Open Access
Transmission Tariff ("OA1T). Additionally, Hells Canyon is limited in ramping ability
due to downstream river level changes of one foot per hour. This severely limits the
ability for Hells Canyon units to ramp to support large deviations in outflow. Idaho
Power sets aside capacity in the pre-schedule or day ahead to cover reserve
requirements and meet load demands. Idaho Power's procedures require the Company
to sell or buy energy to balance the system in pre-schedule based on generation and
load forecasts, this takes into account wind forecasts, as well as limitations on hydro
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY - Exhibit 504
GNR-E-1 1-03
D. Reading: Simplot
Exergy, Clearwater
Page 36
stream flows and the ability to ensure compliance with FERC requirements and the
OArr.
The response to this Request was prepared by Tessia Park, Director Load
Serving Operations, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -34 Exhibit 504
GNR-E-1 1-03
D. Reading: Simplot
Exergy, Clearwater
Page 37
REQUEST FOR PRODUCTION NO. 42: Reference the Direct Testimony of
Tessia Park, page 11, containing the following dispatch costs: Langley Gulch
($22/MWh), coal generators (generally below $30/MWh). These values are different
from those provided for the hourly variable generation costs provided in the confidential
attachment to Staffs Request No. 2. Please explain the discrepancy and provide the
correct dispatch costs for each of the Company's gas and coal plants.
RESPONSE TO REQUEST FOR PRODUCTION NO. 42: In Tessia Park's
testimony, the data stated for the dispatch costs of the Langley Gulch power plant and
the coal generations were representative estimates. These dispatch costs were
representative of average dispatch costs, not specific dispatch costs by resource as
was the data provided in the Company's response to the Idaho Public Utilities
Commission Staffs Production Request No. 2.
The response to this Request was prepared by Tessia Park, Director of Load
Serving Operations, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE THIRD PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY -4 Exhibit 504
GNR-E-1 1-03
D. Reading: Simplot
Exergy, Clearwater
Page 38
REQUEST NO. 5: The direct testimony of Tessia Park discusses generally the
low loading conditions when the proposed Schedule 74 might require curtailment, and
describes a representative example on pages 23-24. Has Idaho Power conducted any
analysis or studies to attempt to estimate the frequency, duration, and magnitude of
curtailments that might be invoked in the future or that would have been invoked in the
past if its proposed Schedule 74 was in place? Please provide a copy of any analysis
or studies. If no analysis or studies have been done, please provide estimates if
possible.
RESPONSE TO REQUEST NO. 5: Idaho Power has not conducted an analysis
or study to estimate the frequency, duration, or magnitude of curtailments that might
have been invoked or would be invoked in the future under the proposed Schedule 74.
Idaho Power estimates that curtailments under Schedule 74 would occur during periods
of low load and be more likely during high water conditions, such as in the spring
months, and during periods of low market prices, which are indicative of there being no
market demand for Idaho Power's surplus energy.
As part of determining the hourly incremental cost in the alternate IRP
methodology proposed in Company witness Bokenkamp's testimony, there are a small
number of hours each year where the hourly incremental cost is zero. While these
zero-cost hours are used in the calculation of the monthly average heavy load and light
load price, they do not estimate the amount of curtailment expected under Schedule 74.
During the zero-cost hours, Idaho Power would still be accepting delivery of QF
generation, and paying the project the appropriate monthly average heavy or light load
price. Similar conditions tend to exist (low load and high water) at times when the
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -6 Exhibit 504
GNR-E-1 1-03
D. Reading: Simplot
Exergy, Clearwater
Page 39
hourly incremental price is zero and curtailment may be necessary under Schedule 74;
however, they are not synonymous.
The response to this Request was prepared by Tessia Park, Load Serving
Operations Director, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -7 Exhibit 504
GNR-E-1 1-03
D. Reading: Simplot
Exergy, Clearwater
Page 40
REQUEST NO. 6: If Idaho Power's proposed Schedule 74 were to be approved
by the Commission and QFs were curtailed during certain low load conditions, would
the avoided cost rates computed based on Aurora analysis be impacted? Has Idaho
Power conducted any Aurora analysis to compute avoided cost rates under an
assumption that QFs could be curtailed under certain low load conditions?
RESPONSE TO REQUEST NO. 6: Avoided cost rates computed by AURORA
are set for the duration of the contract based upon the QF's estimated hourly generation
profile for a period of one year, and this computation is not impacted by possible
curtailment. However, if Idaho Power must pay for curtailment, it must also be able to
recover such payments. If Idaho Power may curtail without payment, no adjustment to
avoided costs through the integration charge is necessary.
In its updated wind integration study, the Company has been careful to not
include any costs associated with curtailment in the wind integration cost analysis. The
AURORA model used by Idaho Power to determine the avoided cost of energy is not
capable of modeling wind curtailment and therefore curtailment is not valued in the
pricing proposed by Idaho Power. Because a certain amount of curtailment is
anticipated in the modeling performed as part of the wind integration study, Idaho Power
does not believe it would be appropriate to account for curtailment in the avoided cost
pricing model.
The response to this Request was prepared by M. Mark Stokes, Power Supply
Planning Manager, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE SECOND PRODUCTION
REQUEST OF THE COMMISSION STAFF TO IDAHO POWER COMPANY -8 Exhibit 504
GNR-E-1 1-03
D. Reading: Simplot
Exergy, Clearwater
Page 41
Service Date: September 13, 2011
DEPARTMENT OF PUBLIC SERVICE REGULATION
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MONTANA
IN THE MATTER OF the Petition of ) REGULATORY DIVISION
NorthWestern Energy for a Declaratory )
Ruling on the Applicability of 18 C.F.R. ) DOCKET NO. D201 1.7.57
' 292.304(1) and ARM § 38.5.1903(1) to ) ORDER NO. 7172
Contracts with Qualifying Facilities )
ORDER REJECTING NORTHWESTERN ENERGY'S REQUESTED DECLARATORY
RULING THAT ITS PROPOSED QUALiFYING FACILITY CURTAILMENT
PROVISION IS CONSISTENT WITH 18 CFR SEC. 292 AND ARM 38.5.1903(1)
INTRODUCTION
1.On July 8, 2011, the Montana Public Service Commission ("Commission")
received the Petition of NorthWestern Energy ("NWE") seeking the Commission's declaration
that the 'curtaiIment" language that NWE proposes to include in new Qualifying Facility ("QF")
contacts is consistent with governing state and federal administrative rules. ARM §
38.5.1903(1) and 18 CFR292.304(f).
2.On July 14, 2011, the Commission issued a public notice of the hung of the
Petition and invited concerned members of the public to file comments by August 1, 2011, while
allowing NWE and others until August 15, 2011 to file reply comments.
3.Initial comments were received from New Moon Ranch, LLC; Hydrodynamics,
Inc.; Sagebrush Energy, LLC; the Montana Department of Natural Resources and
Conservation—State Water Projects Bureau; Two Dot Wind Farm; Natural Resources Defense
Council; Fairfield Wind LLC, Greenfield Wind LLC and Front Range Wind LLC; United
Materials of Great Falls and Exergy Development Group; Renewable Northwest Project; and
Russ Bentley. In these comments, NWE's proposed curtailment language received little or no
support.
Exhibit 505
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 1
DOCKET NO. D2011.7.57, ORDER NO. 7172
4.Reply comments and legal arguments were received from NWE. In its reply
comments (which are discussed below), NWE argued that it alone, and not existing or potential
QFs, should have been allowed to comment in this proceeding on the significant impact of the
proposed curtailment language. NWE also argued that a host of generically-stated "problems"
with the QF regulatory regime are the responsibility of this Commission.'
5.NWE argues in its Petition (pp..1-2) that its obligation to purchase electricity from
QFs produces surplus power situations that harm the interests of NWE and its customers in
certain hours, and that this resulting surplus must be sold for less than the purchase price. To
address this situation, NWE proposes curtailment language for its new QF contracts that would
relieve it of its obligation to purchase QF output during "light load" hours. NWE's proposed
remedy for this situation is the following language:
No Obligation to Acceot Energy: Northwestern shall not be obligated to accept or pay
for Energy from Seller during any period in which, due to operational circumstances, the
acceptance of Energy from Seller and Similarly-Situated Suppliers of energy to NorthWestern is
expected to result in NorthWestern system costs greater than those which NorthWestern would
incur if it did not accept such deliveries, including periods in which NorthWestern generated an
equivalent amount of energy itself. For illustrative purposes only, and without limiting the
circumstances under which NorthWestern might be relieved of the obligation to accept or pay for
Energy from Seller under this section, an example of such a period is a period when
NorthWestern would be forced to shut down a base load or intermediate load plant in order to
accept deliveries of Energy from Seller and such base load or intermediate load plant could not
then be restarted and brought up to its rated output to meet the next period's peak load and
NorthWestern would consequently be required to utilize costly or less efficient generation with
faster start-up or purchase higher-priced energy to meet the demand that could have been met by
the base load or intermediate load plant but for such purchases from Seller. During periods in
which NorthWestern is purchasing energy both from Seller and from Similarly-Situated
Suppliers, the implementation of any curtailments of deliveries of energy is subject to the sole
discretion of NorthWestern provided, however, as between Seller and such Similarly-Situated
"QFs view PIJRPA as creating an entitlement rather than a competitive opportunity. Some large projects are
attempting to disaggregate into smaller projects that qualify for the standard offer rate Furthermore, QFs do not
recognize that intermittent resources are not the equivalent of resources that can be dispatched. Finally QFs seem to
believe that retail customers should subsidize their projects regardless of cost and that they should not be held to the
same commercial terms as other suppliers. Additionally, the Commission has substantially contributed to the
problems. For its part, the Commission has failed to distinguish and establish QF rates that consider the availability
of energy or capacity under peak periods, the expected reliability of the project, and the ability to dispatch the QF
(among other factors), as required by 18 CFR Sec. 292.304(e)(2). lii addition, the Commission has adopted
administrative rules that are inconsistent with federal regulations; under preemption principles, where compliance
with both is an impossibility, the federal regulation preempts the state regulation, and the state regulations are
invalid." Reply Comments, p.2.
Exhibit 505
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 2
DOCKET NO. D2011.7.57, ORDER NO. 7172 .3
Suppliers, such curtailments shall be made on a non-discriminatory basis in accordance with the
NorthWestern Energy Curtailment Protocol attached hereto as Ex.lribit C.2
6. The federal and state regulations that NWE seeks to have interpreted as they may
impact its ability to include the new curtailment language in its QF contracts are 18 C.F.R.
292.304(f) and ARM § 38.5.1903(1).
18 C.F.R. 292.304(f) provides:
Periods during which purchases not required. (1) Any electric utility which gives
notice pursuant to paragraph (1)(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.
(2)Any electric utility seeking to invoke paragraph (f)( 1) of this section must notify, in
accordance with applicable State law or regulation, each affected qualifying facility in time for
the qualifying facility to cease the delivery of energy or capacity to the electric utility.
(3)Any electric utility which fails to comply with the provisions of paragraph (1)(2) of
this section will be required to pay the same rate for such purchase of energy or capacity as
would be required had the period described in paragraph (f)(l) of this section not occurred.
(4)A claim by an electric utility that such a period has occurred or will occur is subject to
such verification by its State regulatory authority as the State regulatory authority determines
necessary or appropriate, either before or after the occurrence.
ARM § 38.5-1903(l) provides:
Each utility shall purchase any energy and capacity made available by a
qualifying facility, except that a utility is not obligated to make purchases from an interconnected
qualifying facility:
(i)during system emergencies if such purchase would contribute to the
emergency;
(ii)as stipulated in the contract between the utility and the qualifying facility;
(iii)it due to operational circumstances, purchases from a qualifying facility will
result in costs greater than those which the utility would incur if it did not make such purchases.
This provision is only applicable in the case of light loading periods in which the utility must cut
back base load generation in order to purchase the qualifying facility's production followed by an
immediate need to utilize less efficient generating capacity to meet a sudden high peak. Any
utility seeking to invoke this exception must notify each affected qualifying facility and the
commission one month prior to the time it intends to invoke this provision. Failure to properly
notify the qualifying facilities and the commission or incorrect identification of such a period
will result in reimbursement to the qualifying facility by the utility in an amount equal to that
amount due had the qualifying facility's production been purchased.
2 NWE did not include Exhibit C with its filing, although the Exhibit was attached to the filing of Hydrodynamics.
Exhibit 505
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 3
DOCKET NO. D2011.7.57, ORDER NO. 7172 4
7.NWE asserts that the number of hours in which it experiences surpluses is
increasing, stating:
As NorthWestern enters into more PPM with QFs, the occurrence of the
operational circumstances described in the preceding paragraphs becomes more frequent and
resulting effects potentially greater.. .Petition, p.4.
NWE did not attempt to quantify the cost and rate impacts of these alleged
conditions.
8.NWE argues that its proposed curtailment language conforms closely to the language
of the federal regulation, that FERC has not rejected similar language in various dockets where
contracts containing that language has been before that Commission (although that language was
not directly addressed by FERC), and that no Montana cases compel the rejection of the
language.
9.Rather than list the arguments of each of the commenters, the Commission will
summarize the arguments that have been presented against the proposed curtailment language.
a.The relevant cost comparison under the CFR is between the QF price and the
operating cost associated with curtailment plus the restart cost of a baseload unit. The CFR
authorizes curtailment only for operation and not for economic reasons, and does not relieve the
utility of its obligation to purchase QF output in the situation described by NWE.
b.The proposed language is too broad in scope and would confer excessive discretion
on NWE to impose curtailments based on a range of economic circumstances. Further, it is not
clear whether NWE would curtail its own generation so that all providers would be treated
similarly.
c.The right under the proposed curtailment language to refuse to purchase QF output
following notice to the QF is fundamentally at odds with the obligation to purchase embodied in
the Public Utility Regulatory Policies Act of 1978 (PURPA) and state law. The proposed
language would authorize economic curtailment when market prices are low, and the resulting
uncertainty would prevent QF developers from arranging affordable financing. NWE's
application for approval of the Spion Kop wind project (Docket No. D2011.5.41) provides that
NWE would enter a PPA as buyer if the Commission declines to preapprove the project;
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however, that PPA does not contain a parallel curtailment provision to that proposed here by
NWE. The proposed language has no upper limit on the number of hours that curtailment could
be imposed, rendering a QF's revenue stream something of a guessing game.
d.NWE argues that the governing federal and state regulations, adopted during a period
of vertical integration, must be construed in light of today's circumstances, when NWE relies
heavily on PPAs from a variety of sources. However, the context of both the FERC and PSC
rules is clearly reduction and restart of baseload power units. If NWE wishes to see those rules
adapted to its changed environment, its remedy is to pursue rulemaking rather than advocating
strained interpretation of these regulations.
e.The proposed curtailment language is excessively broad and would allow NWE to
curtail QF ouput at any time the QF cost exceeded that of power available from the market. The
lack of an upper bound on the potential hours to be curtailed would make financing of a QF
seeking to contract with NWE impossible. Clear guidelines are needed defining conditions such
as "light load" and "sudden high peak," and, absent those guidelines, contracts now in
negotiation should proceed without the disputed language. NWE has contracted for substantially
more energy than it requires to serve its normal load. With 30 MW of new wind QFs having
been added recently, the addition of another 20 MW that will take NWE to the Commission's 50
MW "cap" will hardly burden NWE's shareholders or its customers. NWE's reliance on
California authority is misplaced; California's curtailment cases compare the cost of self-
generation to the cost of QFs—there is no comparison to market purchases. Curtailment policy
should apply equally to the utility and its resources that are supplied under PPAs and to QFs.
Spion Kop, if it is approved, should live by the same rules NWE has proposed for other
resources. QFs should be allowed to obligate themselves to a legally-enforceable obligation that
does not include the arbitrary curtailment language; NWE's insistence on this provision prevents
the QF from exercising that right.
f.NWE consistently attempts to limit its requirement under PURPA to purchase
electricity from QFs; this filing is another effort to introduce uncertainty that will compound the
difficulty already facing QFs in obtaining financing. NWE seeks to incorporate cost analysis for
intermediate load plants, but that term is not defined in federal or state rules. While hydropower
is much more predictable than the output of wind facilities, NWE's language would nonetheless
extend operational limitations to that type of plant without justification.
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DOCKET NO. D2011.7.57, ORDER NO. 7172 ONE
g.In framing its rules FERC recognized that avoided costs would vary from time to
time. NWE ignores that fact by picking a pafticular operational circumstance when avoided
costs are low, and then seeks unbridled authority to curtail QFs during those hours. This
approach finds no support in the language of PTJRPA, in the rules implementing PURPA, or in
precedent. The term "operational circumstances" was intended to be narrowly construed to
include the situation where baseload generation must be reduced and cannot be brought back to
its former output level in a timely manner. The full scope of NWE's intent is not clear because
its proposed curtailment language is so general in nature. Because of the uncertainty regarding
application of the language, a QFs revenue stream will not be predictable.
h.In fact, one QF, Horseshoe Bend, accepted curtailment language very similar to that
proposed by NWE in this case. That contract covers sales to NWE in the summer of 2011. In
the month of July, N 1NE invoked curtailment in 50 separate hours, only a few of which would
normally be considered "light load hours." NWE has not provided Horseshoe Bend with
documentation of the basis for its curtailments. The NWE language is excessively broad and
provides NWE with significant discretion, while providing QFs With no assurance that similarly-
situated generators will be treated identically.
i.The proposed curtailment language allows NWE to curtail deliveries in its sole
discretion so long as similarly situated suppliers are treated in a non-discriminatory nature. This
provision would render NWE's purchase obligation under PURPA and under Montana law
meaningless. Similar curtailment language sought by The Montana Power Co. was rejected by
the Commission in 1983. Further, this Commission has held that relative rate certainty is
essential. Future revenue streams must be predictable if new QF projects are to have access to
capital. Finally, this issue must be resolved quicidy if current federal programs that encourage
QF development are to be available to developers, since projects must be substantially advanced
in development in 2011 if federal subsidies are to be secured.
10. NWE's Reply to the Initial Comments of the QFs seeks to portray NWE as the
protector of its customers. NWE acknowledges that those opposing the Petition forcefully
present their interests and needs, but NWE believes that they ignore the delicate balance that
must be achieved between QF interests and PURPA's requirements for consumer indifference.
NWE is a voice for the utility's interests and also for its retail customers' interests. Reply, p. 3.
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DOCKET NO. D2011.7.57, ORDER NO. 7172 7
ANALYSIS
11. The heart of NWE's legal argument is that its proposed curtailment language is
consistent with 18 CER 292.304(f)(I)? This comparison is presented at pages 4 and 5 of the
Reply. NWE relies on the parallel language of the two provisions which states that the purchase
obligation can be avoided during periods when "operational circumstances" cause costs greater
than those the purchasing utility would incur if not for the QF deliveries. However, in advancing
this argument, NWE wholly ignores several key points. First, the preamble of the federal rule
upon which NWE rests its case states that
This section was intended to deal with a certain condition which can occur during light
loading periods. If a utility operating only base load units during those periods were
forced to out back output from the units in order to accommodate purchases from
qualifying facilities, these base load units might not be able to increase their output level
rapidly when system demand for power later increased. As a result, the utility would be
required to utilize less efficient, higher cost units with faster start-up to meet the demand
that would have been supplied by the less expensive base load unit had it been permitted
to operate at a constant output. 45 Fed. Reg 12227 (Februrary 25, 1980)
The Commission's rule at issue contains language that closely parallels the FERC preamble.
ARM § 38.5A903(l), states that:
(iii) if, due to operational circumstances, purchases from a qualifying facility will result
in costs greater than those which the utility would incur if it did not make such purchases.
This provision is only applicable in the case of light loading periods in which the utility
must cut back base load generation in order to purchase the qualifying facility's
production followed by an immediate need to utilize less efficient generating capacity to
meet a sudden highpeak.
Therefore, the Commission concludes that there is no conflict between its rule and that of FERC.
NWE's reading of the federal and state rules, and its proposed curtailment language, must be
rejected. Even if the FERC's rule and its intent were as NWE wishes, the ARM clearly prohibits
NWE's language. Further, federal law authorizes the State to adopt its own requirements in this
3 The language of the FERC regulation that NWE relies on reads as follows: "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 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"
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DOCKET NO. D2011.7.57, ORDER NO. 7172 8
Beginning on or before the date one year after any rule is prescribed by the commission
under subsection (a) of this section or revised under such subsection each State
regulatory authority shall, after notice and opportunity for public hearing, implement
such rule (or revised rule) for each public utility for which it has ratemaking authority.
16 USC Sec. 824a-3(f)(1)
The Montana Legislature has authorized the Commission to "adopt rules further defining the
criteria for qualifying small power production facilities, their cost-effectiveness, and other
standards." Sec. 69-3-604, MCA.
12.In light of the foregoing, the Commission finds that NWE's proposed curtailment
language is not authorized by state or federal law, and NWE. is prohibited from demanding that
new QFs with whom it is negotiating accept such language as a pre-condition of contracting with
NWE for the sale of their output to the utility. If market conditions occasionally result in prices
less than NWE's tariffed avoidable costs, that is not in itself a sign that the principle of consumer
indifference is unlawfully being violated—no more than if a long-term acquisition of NWE's
own were to result in a fixed-and-variable cost-per-unit which were higher than prices available
on the spot market. Sec. 18 CFR 292.304(b)(5).
13.It is also important to note that NWE's QF tariffs make no provision for the
reduction of purchase volumes for curtailments sought by the buyer. For example, NWE
Schedule No. QF- 1 provides that the specified purchase prices, Options 1 (a)-(c) provide that the
full price will be paid for deliveries at "all hours"; Option 2(a) refer to purchases during "each
hour", Option 2(b) refers to metered kWh delivered to the Utility; and Option 3 applies the
purchase price to deliveries at "all hours." The Commission concludes that NWE is bound by
the provisions of its tariffs, as well as State and Federal rules, as discussed above.
14.NWE' s Reply Comments contain several arguments that warrant a response.
NWE's critique of the Commissions system of QE regulation ignores NWE's obligation to
advocate and support avoidable cost calculation methods and tariff rates with high quality
evidence that will withstand critical scrutiny. If the avoided cost of intermittent resources is less
than the rates contained in MPSC tariffs, NWE is not lacking in opportunities to prove that case.
When NWE's electric power supply plans regularly include wind resources within the preferred
portfolios, NWE is not advocating a limit on wind procurement. Indeed, NWE recently
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DOCKET NO. D2011.7.57, ORDER NO. 7172
advocated in Docket No. 112010.7.77 a separate rate for wind QFs of 10 MW or less. The
Commission agrees with commenters that it is not clear why the "back up" PPA for Spion Kop
(the contract under which NWE would secure wind if its own acquisition of the wind farm is
rejected) does not contain a curtailment provision like that at issue here.
15.A sound approach to implementing PURPA is particularly important now as
NWE transitions from a default supplier in a deregulated retail market to a vertically integrated
utility with an electricity supply monopoly. PURPA requires a neutral playing field for qualifying
facilities and facilities that NWE may prefer to own. So long as PURPA is law, the Commission
will enforce it. While rejecting much ofNWFs criticism of its approach to implementing
PURPA, the Commission is open to working with NWE and others to improve that approach. To
the extent NWE has ideas in this regard it should proactively offer them in its biennial QF tariff
filings or petitions for rulemaking. These are the proper places for reform, not a petition for
declaratory judgment seeking to extend an existing rule to a situation that clearly does not apply.
16.As to NWE' s argument that comments of QFs should not have been solicited in
this proceeding (Reply Comments, pp. 6-9), counsel for NWE is well aware that receipt of
comments from interested parties in declaratory ruling proceedings has been the longstanding
practice of the Commission. Presumably, the rule requiring the petitioner seeking a declaratory
ruling to list "the name and address of any person known by petitioner to be interested in the
requested declaratory ruling" does so precisely so that the views of those persons can be
obtained. Sec. 1.3.227(2)(h), ARM. This practice was followed in a recent NWE declaratory
ruling request involving the Turnbull Project. Docket No. 1)2009.11.151. Finally, the
Commission, in designing its procedures, is obligated to
• . .include a method of affording interested persons reasonable opportunity to submit data,
views, or arguments, orally or in written form, prior to making a final decision that is of
significant interest to the public. Sec. 2-3-111, MCA.
The solicitation of comments from interested parties in this proceeding is necessary to comply
with the Commission's statutory obligation to provide a meaningful opportunity for public
participation as required by statute.
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DOCKET NO. D2011.7.57, ORDER NO. 7172 10
ORDER
The Commission rejcts NWE's proposed declaratory ruling that its proposed curtailment
language is consistent with 18 C.RR. §292.304(1) and ARM § 38.5.1903(1).
DONE AND DATED the 1st day of September 2011 by a vote of 3 to 2. Commissioners
Gallagher and Molnar dissenting.
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DOCKET NO. D2011.7.57, ORDER NO. 7172 11
BY ORDER OF THE MONTANA PUBLIC SERVICE COMMISSION.
4`-TRAVIS KAIULLA, Chairman
GAL73UTSCIie'a1r
BRAD MOLNAR, Commissioner (Dissenting)
a.
Co"ss-ioner
ATTEST:
eisha Solem
Commission Secretary
(SEAL)
NOTE: Any interested party may request the Commission to reconsider this decision. A
motion to reconsider must be filed, within ten (10) days. See ARM 38.2.4806.
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Page 11
Service Date: September 13, 2011
DEPARTMENT OF PUBLIC SERVICE REGULATION
BEFORE THE PUBLIC SERVICE COMMISION
OF THE STAE OF MONTANA
IN THE MATTER OF the Petition of ) REGULATORY DIVISION
NorthWestern Energy for a Declaratory )
Ruling on the Applicability of 18 C.F.R.. ) DOCKET NO. D2011.7.57 -
292.304(f) and ARM 38.5.1903(1) to ) ORDER NO. 7172
Contracts with Qualifying Facilities )
DISSENT OF COMMISSIONER
BRADLEY A MOLNAR TO ORDER NO. 7172
INTRODUCTION
On July 8, 2011, the Montana Public Service Commission (Commission) received a petition
from NorthWestern Energy (NWE) seeking declaration of proposed curtailment language NWE
proposes for new Qualifying Facility (QF) contracts. They offered ARM 38.5.1903(1) and
C.F.R. 292.304(f) as proof of their capacity to include curtailment language.
On September 1, 2011, the Commission, without a public hearing, voted 3-2 to reject NWE's
proposal to include in future QF contracts language giving the ability to curtail purchases when
market conditions (including light load hours) are such that certain QF purchases are not
necessary so the energy must be sold at a loss. This is a continuation of the Commission's
economic assault on customers of regulated utilities. Using tortured logic the Commission has
consistently ignored the plain wording of federal and state consumer protections designed to
allow "market ready" small generators into the regulated market without consumer harm. I
firmly believe those outside the narrow band of special interests profiting from below costs sales
would agree this ruling ignores/defies various ARMs and laws in order to promote various
industrial and political agendas.
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DOCKET NO. D2011.7.57, ORDER NO. 7172—Molnar Dissent 2
ANALYSIS
One of the first issues was whether the various commenters should have been allowed to
comment. I concur with staff, indeed they should be allowed to comment. However, their
comments did not stick to the question of curtailment language but went to financing
considerations. Unsupported/undocumented discussions on impacts on unnamed credit sources
should never have been iii our legal conclusions.
The only question is whether NWE "shall not be obligated to accept or pay for Energy from
Seller during any period in which, due to operational circumstances, the acceptance 'of Energy
from Seller and Similarly-Situated Suppliers of energy to NorthWestern is expected to result in
NorthWestern system costs greater than those which NorthWestern would incur if it did not
accept such deliveries...," as well as, is there a legal basis for or against the conclusion?
This is not difficult. In multiple dockets, final orders and discussions, Commission stafl
Commissioners, and the Montana Consumer Counsel (which ignored this opportunity) have all
alluded to the overarching PTJRPA dictate that while the goal is to provide an opportunity for
small generators to sell their product consumers must be made "indifferent." This is referenced
on P.6 Para 10 and denigrated away with the use of "occasionally" in lieu of the more accurate
"predictably" which goes fo the need for curtailment. Men of good heart could not argue that
buy high/sell low (and stick consumers with the difference) comports to this mandate.
The referenced ARM 38.5.1903(l)(ii), clearly states that curtailment is allowed if stipulated in
the contract, and 18 C.F.R. 292.304(f) seems to mirror the requested language in the NWE
proposed language and gives all the authority needed without PSC preapproval. The request for
a declaratory ruling seems beyond an abundance of caution and causes one to look for other
rationale. ARM 38.5.8204(a) also speaks to this issue by clearly stating that "customers should
be supplied with reliable, stably and reasonable priced (electricity) at the lowest long term price."
After one notes that consumer indifference is our guide under federal and state policy one should
note the lack of mandated concern for financial markets and access to federal subsidies. The
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mandate of "reliability" was addressed on page P.8 Para 12 where it was labeled an "unavoidable
complexity" then deleted. The proposed language avoids much of the complexity.
ARM 38.5. 8219 plainly mandates the mitigation of risk through analysis of (d) competitive
prices and (i) contract terms and conditions. This is plainly a mandate to NWE. The,
Commission is supposed to enforce ARM 38.5.8219, not ignore it. The Commission opted to
shift the risk from QF financiers and QF developers to consumers. This is outrageous,
undefendable and illegal.
The ARMs provide procedure to implement the law. MCA 69-8-419 instructs the utility at
(2)(a) to provide adequate and reliable electricity supply service at the lowest long-term total
cost, (c) identify and cost effectively manage and mitigate risks related to its obligation to
provide electricity supply service, and (d) use a competitive procurement process whenever
possible.
The Commission's 3-2 vote on the issue of economic curtailment is direction to NWE to violate
federal and state laws and policies leading to extreme regulatory uncertainty and legal risk as
NWE's legal obligations are not lifted by rogue Commission actions. Now that NWE has raised
the issue they are obligated to achieve resolution.
GENERAL
The constant references to Spion Kop for justifications area major concern. This order dealt
strictly with curtailment language in future QF contracts. Spion Kop is not a QFso any
analogies are immaterial as they are not covered in, nor is there a mandate from, PURPA. Rather
it seems like childish finger pointing after a playground scuffle wherein justification seems to
hinge on, "Oh yeah, how about him"; rather than a discussion of the point in controversy.
More importantly Spion Kop is a docketed matter. Arguably we have pre-approved non-
curtailment language for Spion Kop before the hearing.' Never during my tenure have we used a
docketed item for a point of discussion outside the docket. Rather we have been consistently
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DOCKET NO. D201 1.7.57, ORDER NO. 7172 - Molnar Dissent 4
warned about discussing dockets or possible findings. Perhaps the entire Commission now needs
to consider recusal on the Spion Kop docket.
On page nine Commissioner Kavulla once again uses the negative attention seeking device that
NWE should have chosen a venue and time more to his personal preference. That seeking a
declaratory ruling not fitting his unpublished time frame is somehow unjustified, worthy of his
contempt and cause for denial.
Having read and reread the ARMs concerning the request for declaratory rulings I find zero
references to preferences for "biennial QF tariff filings" OE "petitions for rule makings." Nor are
there any such challenges in the evidentiary record. There are only requirements for filings, not
a list of mandates for venue shopping prior to a request for a declaratory ruling. How our legal
department allowed these unfounded, undocumented, unsubstantiated mutterings to be included
in a legal document is cause for introspection.
Recently, at a location near Red Lodge, MT, Chairman Kavulla lambasted Southern Montana
Electric (SME) for purchasing power then, because of an over-generation event, selling it at a
loss and passing the stranded costs onto consumers. This was witnessed by several utility
personnel present (perhaps the reason for this request) and reported in the press. Now he argues
that proper policy is that planned over-generation with resulting below cost sales should be a
stranded cost borne by NWE customers.
Such hypocrisy spouted by the Chairman generates the perception of regulatory uncertainty and
predictably higher costs (rather than lowest costs possible) for regulated utility and co-op
customers alike regardless of his forum.
CONCLUSION
NWE has specific authority to contract for QF power with curtailment language especially
during light load hours. And they have federal and state statutory mandates to curtail on an
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DOCKET NO. D2011.7.57, ORDER NO. 7172 - Molnar Dissent 5
economic basis to maintain consumer indifference. This was an unnecessary but interesting
exercise that perhaps had more to do with SpiOn Kop than Two DoL
I am perplexed as to why the Montana Consumer Counsel opted to be silent on this issue.
Perhaps they have given up on the Montana Commission and are picking their battles. Perhaps
they should intervene and ask for reconsideration and possible judicial review. Perhaps.
Over the last several decades too many Montana Commissioners have seen themselves as
political engineers or environmentalists with an agenda dedicated to servicing the desires of QF
developers rather than to consumer indifference and have, or rather continue to cost consumers
literally hundreds of millions of dollars and put a strain on our economy. The findings of Order
7172 are a continuation of that sad heritage. There is no interpretation of any ARM or any MCA
cite, made by myself, NWE, or any intervenor, that allows the purposeful over generation of
electricity for the purpose of below costs sales from any type of generation.
While the Commission may have, correctly or incorrectly, discouraged certain specific
curtailment language for future QF contracts NWE still has a legal obligation to implement
curtailment to insure consumer indifference and statutory compliance. Hopefully a more
populist future Commission shall hold them to it or, if the courts have not acted, help them
implement it.
BRAD M&NAR, Commissioner
MT PSC District II
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Page 16
Service Date: September 13, 2011
DEPARTMENT OF PUBLIC SERVICE REGULATION
BEFORE TUE PUBLIC SERVICE COMMISSION
OF THE STATE OF MONTANA
IN THE MATTER OF the Petition of ) REGULATORY DIVISION
NorthWestern Energy for a Declaratory )
Ruling on the Applicability of 18 C.F.R... ) DOCKET NO. D2011.7.57
292.304 (f) and ARM 38.5.1903 (1)to ) ORDER NO. 7172
Contracts with Qualifying Facilities )
CONCURRING OPINION OF
COMMISSIONER TRAVIS KAVIJLLA
The current Qualifying Facility regime is by no means desirable. When NorthWestern Energy
Corp. ("NorthWestern" or "applicant" or "petitioner") files its resource procurement plan, it sets
in motion another docket whereby the Commission pursuant to PUTRPA and Montana law plays
market maker and sets out to do the impossible: creating a durable rate which reflects the
"avoided cost" of energy over a short and long term. As the last few years make clear, however,
there is nothing consistent or durable about the wider economy to whose vicissitudes the energy
market is subject. A meaiingful avoided cost is difficult to concoct if it is only being revised
biennially or at an even longer interval. Similarly, it is difficult to ignore the fact that this
Commission's rules have created a mode of political economy where nearly all QFs are built to a
scale (10 aMW) which is decreed as an upper limit to a QF standard-offer contract by the
Commission's administrative rules. Perhaps the eventual answer lies in taking this Commission
out of the market-making game and leaving that role to the market itself via processes which do
not revolve around fixed and inflexible prices like requests for proposals. None of the foregoing
is directly at issue in this docket, but is so inexorably linked to any matter touching upon QF
policy that it deserves enunciation as a preface.
At issue here is the applicant's attempt to use what is essentially a dead letter of the
Commission's administrative rules, explicitly intended for a utility which owns a considerable
amount of base-load generation, to introduce an utterly novel concept into the realm of PURPA-
based regulation as it exists in Montana: one which is neither countenanced by the clear language
of the governing tariff, which states that a QF shall be paid for "all hours" of generation, nor by a
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DOCKET NO. D2011.7.57, ORDER NO. 7172–Kavulla Concurring Opinion 2
considered reading of the rule itself; nor, more quaintly, by a rudimentary sense of fair play and
nondiscriminatory access which animates Montana's implementation of PURPA.
While sensitive to the outcomes wrought upon the system by an antiquated regime of QF
regulation—which, inopportunely, NorthWestern seeks to exploit in this petition, rather than
alter in a rulemaking—the Commission should try to enforce the letter and spirit of the law to the
best of its ability. This includes an attempt to maintain impartiality between the assets
NorthWestern owns or intends to own, and of those with whom it is entering into agreements.
That guideline, and not an unremitting embrace of the status quo, is the spirit in which this
Order, I hope, will be read.
The Dissent to this Order requires a few points of correction.' First, it confuses what is permitted
under state and federal rules' existing curtailment language by conflating "operational
conditions"—when curtailment is explicitly contemplated—with "market conditions." One is not
the other. Market conditions, by which I mean a more expansive notion than the truncated view
of spot prices the Dissent brooks, are anticipated by the avoided-cost tariffs. This Commission's
tariffs put forth a multifaceted calculation of avoided cost resulting in three options. One option
is premised upon a price available at market, another upon the acquisition of a long-term base-
load asset (pegged, in the last tariff, to Coistrip W, an avoided cost essentially established when
the Commission, including the dissenter, voted to allow the utility's acquisition of it), and the
third is based upon the cost of a long-term wind asset whose acquisition to comply with public
policy is anticipated by the procurement plan. The asset being avoided, in other words, is
different in term or fuelstock or uncertain other costs like wind integration in each of the three
options, and therefore results in different avoided-cost rates. The Dissent should, but does not,
ask itself: Could the prevailing low market prices be secured over a 25-year period? Obviously
not
The Dissent is accordingly confused about what is meant by "consumer indifference." The
consumer is indifferent to whether the utility pays a spot price to a QF generator equal to what it
'Indeed, the Dissent requires more than a few points of correction. But in the interest of brevity, this Concurring
Opinion, because the Dissent is unintelligible in parts, will not attempt to impute a meaning to its language.
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DOCKET NO. D20 11.7.57, ORDER NO. 7172– Kavulla Concurring Opinion 3
would pay at the spot market. But the consumer also is indifferent whether NorthWestern buys
from a coal-fired plant in which the utility owns a stake versus purchasing from a different
generator—if the price paid on- and off-peak is the same. So, too, does the consumer not care
whether NorthWestern complies with a public-policy requirement by obtaining its own wind
asset, signing a non-QF power-purchase agreement with a wind company, or signing to buy with
a small QF. The avoided cost and terms and conditions of a QF contract should, then, reflect as
much as possible those which prevail with respect to non-QF generators or purchases: that is the
concept of indifference which appears to elude the Dissent.
There are numerous other errors in the Dissent. It miscoinprehends the nature of this year's
overgeneration event and what it does and does not mean for the state's wholesale co-ops and
utilities. It implies that a declaratory judgment's issuance in the absence of a public hearing is
somehow improper. It pretends that the Order's "legal conclusions" are premised on a QF's
concern over obtaining financing, when that point was merely reiterated within the Order, not
advocated by it, as a comment the Commission had received (Order, p.5). Insidiously, even
while inveighing against the "regulatory uncertainty" to which the Order will supposedly
contribute, the Dissent appears to encourage NorthWestern to violate the same Order.
At its core, the Dissent is schizophrenic. While calling for a less activist Commission—a notion
with which I am sympathetic—it forwards a vision of PURPA which goes far beyond the scope
of the petition and itself engages in a dismal activism which is totally at odds with the clear
meaning of the law and with the reality of electrical markets. Even while branding itself
"populist," ironically the only thing the Dissent would accomplish is to encourage monopolism
and set up a parallel set of rules which binds some but not others.
I CONCUR with the Order.
Travis Kavulla, Commissioner
Exhibit 505
GNR-E-1 1-03
D. Reading: Simplot,
Exergy, Clearwater
Page 19
Service Date: October 14, 2011
DEPARTMENT OF PUBLIC SERVICE REGULATION
BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MONTANA
IN THE MATTER OF the Petition of ) REGULATORY DIVISION
North Western Energy for a Declaratory Ruling )
on the Applicability of 18 C.F. R. § 292304(1) ) DOCKET NO. D201 1.7.57
and ARM § 38.5.1903(1) to Contracts with ) Qualifying Facilities ) ORDER NO. 7172a
ORDER ON RECONSIDERATION
1.The Montana Public Service Commission (MPSC or Commission) on September
13, 2011, issued Order 7172 (Order) rejecting the proposed contract curtailment language of
NorthWestern Energy (NorthWestern or NWE) and holding that the proposed language was
inconsistent with the rules of this Commission and the Federal Energy Regulatory Commision
(FERC) regarding qualifying facilities (QFs). Order, p. 8. On October 7, 2011, NWE filed a
Motion for Reconsideration (Motion).
2.MPSC denies the Motion for the reasons outlined below.
Background
3.The proposed NWE contract language is described in the NWE Petition, which
was filed on July 8, 2011. Order, pp. 2-3. That language is further explained in Exhibit C to
NWE's proposed QF contract. Although NWE did not supply the Commission with that Exhibit,
it was contained in the August 1, 2011, Comments of Hydrodynamics.
4.The Motion asks that the Commission address four issues on reconsideration, and
that it "identify each perceived shortcoming in North Western's curtailment proposal, along with
Exhibit 505
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Page 20
DOCKET NO. D2011.7.57, ORDER NO. 7172a 2
the specific legal basis for those conclusions, such that North Western can move forward on a
fully-informed basis." Motion, p. 12.
Issue 1 "[TI he Order's broad, sweeping rejection of North Western's curtailment
provision directly conflicts with a core requirement of PURPA—that a utility need not
purchase power from a QF when negative avoided costs would result..."
5.The Order at pages 7 and 8 compared NWE's proposed language to FERC and
MPSC rules and FERC discussion in the rulemaking process, emphasizing the limitation to
curtailment in which "operational circumstances" require cut backs of base-load generation
"followed by an immediate need to utilize less efficient generating capacity to meet a sudden
high peak." ARM Sec. 38.5.1903 (1), as quoted at Order 7172, p. 7. While already quoted at p.
7 of the Order, that language apparently bears repeating. The rule provides that a utility is
relieved of its obligation to purchase QF output
(iii) if, due to operational circumstances, purchases from a qualifying facility will result
in costs greater than those which the utility would incur if it did not make such purchases.
This provision is only applicable in the case of light loading periods in which the utility
must cut back base load generation in order to purchase the qualifying facilities
production followed by an immediate need to utilize less efficient generating capacity to
meet a sudden high peak.
6.NWE's proposed language is inconsistent with and far exceeds the scope of this
rule. NWE's contract language, including Exhibit C, describes a planning activity that the utility
will conduct to determine whether a surplus exists. Total load is compared to total resources. If
a surplus exists in light load periods, the utility reserves the right to declare a surplus and allocate
curtailments in any manner it determines appropriate. By contrast, an operational circumstance
(as contemplated by the rule) would most likely be a plant-related occurrence.
7.NWE stresses a general formulation by FERC of its desire to avoid negative
avoided costs (and resulting payments by QFs to the utility) from the FERC rulemaking Order
(Motion, p. 5), but ignores FERC's rule that acknowleges that long-term avoided costs will at
times exceed prices from the market or contracts of different terms. 18 CFR Sec. 292.304 (a)(5).
Exhibit 505
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DOCKET NO. D2011.7.57, ORDER NO. 7172a 3
Issue 2 "[Tlhere is some indication that the Order is based on a legal conclusion that
PURPA restricts the definition of baseload resources to physical assets that are owned by
North Western—to the exclusion of long-term PPAs."
8.NWE believes that the Order suggested that QF curtailment rules only apply if
base load resources are owned by the utility. To the extent there is an ambiguity, the MPSC
notes its view that, under the current rules, curtailment may legitimately be triggered when the
utility's resources consist of a mix of owned and purchased resources.
9.Whether baseload resources are owned or purchased, this Commission's rule
provides that necessary preconditions would still apply. In the case of a purchase agreement,
necessary preconditions would include a "take or pay" provision, high start-up costs, and a lag in
re-start times. Then other peak-load contracts would have to be relied upon in the interim while
the base-load contracts were curtailed or "cut back" from generation, awaiting start-up. If such a
situation does exist, necessitating the curtailment which NWE is arguing for, then NWE should
make the Commission aware of it. The rule, however, does not contemplate curtailment due to
excess purchases or for the sake of achieving a lower total cost from the resource stack resulting
from market conditions, as discussed in response to Issue 1.
Issue 3 "[To] the extent the Order may reflect commenters' allegations that
NorthWestern's proposal seeks 'excessive discretion'. ..or 'unbridled authority'..., the
Order is based on groundless criticism."
10.NWE is encouraged to review its proposed curtailment provision, which contains the
following language:
During periods in which North Western is purchasing energy both from Seller and
Similarly-Situated Sellers, the implementation of any curtailments of delivery of energy
is subject of the sole discretion of NorthWestern...
Exhibit 505
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DOCKET NO. D2011.7.57, ORDER NO. 7172a 4
The provision continues by alluding to the language of Exhibit C to the contract. Exhibit
C provides that:
A determination of the amount of scheduled energy purchases to be curtailed and the
Sellers to whom the curtailment procedures will apply is subject to the sole discretion of
NorthWestern....
The broad scope of discretion NWE attempts to reserve to itself (as well as the potential
for disparate treatment of QFs) speaks for itself, and could result in discrimination among QFs
that is inconsistent with federal and state rules.
Issue 4 "[T]he Order incorrectly concludes that NorthWestern's Schedule No. QF-1
somehow overrides the curtailment regulations of both FERC and this Commission."
11.The MPSC agrees that the QF- 1 tariff is not controlling; however, it suggests that
NWE should modify it tariff to eliminate any inconsistencies.
Conclusion
12.The curtailment provision that NWE asks the Commission to authorize is at odds
with the utility's own practice in light of some very recent history. NWE did not insist on
curtailment language in the first three wind QF contracts which it signed in the past twelve
months (Musselshell I and 2 and Gordon Butte). Nor did NWE insist on inclusion of
curtailment language in its Power Purchase Agreement with Compass Wind. Docket No.
2011.5.41. This contract also provided the price point (i.e., the proposed avoided cost) which the
utility asked this Commission to use as the premise for rates offered to QF wind projects.
Docket No. D2010.7.77. Then, in July of this year, QF curtailment was advanced with rhetorical
urgency with the filing of this proceeding and in NWE's most recent Motion. Whatever NWE's
motives, its actions are inconsistent with its rhetoric. For this Commission to approve this about-
face in policy would be inconsistent with the regulatory objective of providing consistent
treatment to entities that are similarly-situated.
Exhibit 505
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Exergy, Clearwater
Page 23
DOCKET NO. D2011.7.57, ORDER NO. 7172a 5
13. In other decisions contemporaneous with this Order, the MPSC is attempting to
rectify problems that it perceives in QF policy.
ORDER
NOW THEREFORE IT IS ORDERED:
That the Motion for Reconsideration of NWE is denied.
DONE AND DATED this 13th day or October 2011 by a vote of 3 to 2. Commissioner
Molnar and Gallagher dissenting.
Exhibit 505
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Page 24
DOCKET NO. D2011.7.57, ORDER NO. 7172a 6
BY ORDER OF THE MONTANA PUBLIC SERVICE COMMISSION
TRAVIS KAVIJLLA, Chairman
GAIL GUTSCHE, Vice Chair
W.A. GALLAGHER, Commissioner (Dissenting)
BRAD MOLNAR, Commissioner (Dissenting)
JOHN VINCENT, Commissioner
ATTEST:
Aleisha Solem
Commission Secretary
(SEAL)
Exhibit 505
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Exergy, Clearwater
Page 25
REQUEST FOR PRODUCTION NO. 2: Please provide copies of all documents
related to Idaho Power's acquisition of RECs from existing or proposed QF PRUPA [sic]
projects.
RESPONSE TO REQUEST FOR PRODUCTION NO. 2: Idaho Power objects to
this Request on the grounds of relevance. The Direct Testimony of Lisa A. Grow
submitted in this proceeding specifically states, ". . . the Company has no specific
request of the Commission in this regard [i.e., related to RECs] at this time." Grow
Testimony at p. 14, 11. 6-8. Since Idaho Power has no specific request regarding RECs
in this proceeding at this time, questions related to RECs are irrelevant and beyond the
scope of this docket.
Idaho Power further objects to this Request as it is overly broad and would be
unduly burdensome for the Company to provide the information requested.
In addition, some of the requested material is or may be privileged and protected
by the attorney-client privilege as well as the attorney-work product doctrine.
Idaho Power does not specifically seek to acquire RECs from existing or
proposed qualifying facility ("QF") Public Utility Regulatory Policies Act of 1978
("PURPA'3) projects. Idaho Power includes the environmental attribute language below
in initial Idaho draft PURPA agreements supplied to proposed PURPA projects.
Under this Agreement, ownership of Green Tags and
Renewable Energy Certificate (RECs), or the equivalent
environmental attributes, directly associated with the
production of energy from the Seller's Facility sold to Idaho
Power will be governed by any and all applicable Federal or
State laws and/or any regulatory body or agency deemed to
have authority to regulate these Environmental Attributes or
to implement Federal and/or State laws regarding the same.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY .3 Exhibit 506
GNR-E-1 1-03
D. Reading: Simplot,
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Page 1
During the process of negotiating the draft PURPA agreements into final form,
Idaho Power and some counterparties have negotiated modifications to the above
language that has resulted in either (1) Idaho Power owning 50 percent of the
environmental attributes created by the project for the entire term of the Firm Energy
Sales Agreement ("FESA") or (2) the project retaining ownership of the environmental
attributes for the first half of the FESA term with Idaho Power retaining ownership of the
environmental attributes for the last half of the FESA term.
Listed below are the PURPA projects from which Idaho Power has environmental
attribute ownership rights.
Project Name
Environmental
Attribute
Ownership
Description
IPUC Case
number
Idaho Public Utilities
Commission Order
Number Approving
the FESA
Fargo Drop Hydroelectric 50%* IPC-E-1 1-27 32451
Dynamis Ada County Landfill Project 50% IPC-E-1 1-25 Pending Approval
High Mesa Wind Project 10/10** IPC-E-11-26 Pending Approval
Murphy Flats Solar Power Project 50% IPC-E-1 1-10 32384
Clark Canyon Hydroelectric 10/10 [PC-E-1 1-09 32294
Rockland Wind Farm 10/15*** IPC-E-1 0-24 32125
*50% Project and Idaho Power each own 50 percent of the environmental attributes for the
full term of FESA.
**10/10 Project owns environmental attributes during first the 10 years of the 20-year FESA;
Idaho Power owns environmental attributes for the second 10 years.
***10/15 Project owns environmental attributes through the end of calendar year 2021. Idaho
Power then owns the environmental attributes with the beginning of calendar year
2022 through the term of FESA (a minimum of 15 years as this is a 25-year
agreement).
The response to this Request was prepared by Randy C. Allphin, Senior Energy
Contract Coordinator, Idaho Power Company, in consultation with Donovan E. Walker,
Lead Counsel, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST PRODUCTION REQUEST
OF EXERGY DEVELOPMENT GROUP OF IDAHO TO IDAHO POWER COMPANY ..4 Exhibit 506
GNR-E-1 1-03
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 4th day of May, 2012, a true and correct copy of the
within and foregoing TESTIMONY OF DR. DON READING ON BEHALF OF EXERGY
DEVELOPMENT GROUP OF IDAHO, LLC, J R SIMPLOT COMPANY AND
CLEARWATER PAPER CORPORATION was served as shown to
Jean D Jewell, Secretary X Hand Delivery
Idaho Public Utilities Commission U.S. Mail, postage pre-paid
472 West Washington - Facsimile
Boise, Idaho 83702 - Electronic Mail
jean.jewell(puc.idaho.gov
Donald Howell X Hand Delivery
Kris Sasser U S Mail, postage pre-paid
Idaho Public Utilities Commission - Facsimile
472 West Washington Electronic Mail
Boise, Idaho 83702
donald.howell@,puc.idaho.gov
krisine.sasser(puc.idaho.gov
Donovan E. Walker - Hand Delivery
Jason B Williams —U .S. Mail, postage pre-paid
Idaho Power Company - Facsimile
P0 Box 70 X Electronic Mail
Boise, ID 83707-0070
dwalker(idahopower com
jwilliams gidahopower.com
Michael G Andrea - Hand Delivery
Avista Corporation _U.S. Mail, postage pre-paid
P.O. Box 3727 - Facsimile
Spokane, WA 99220 X Electronic Mail
michael andrea(1)avistacorD com
Daniel Solander - Hand Delivery
PacifiCorp/dba Rocky Mountain Power —U .S. Mail, postage pre-paid
201 5 Main St Ste 2300 - Facsimile
Salt Lake City, UT 84111 X Electronic Mail
daniel solander@pacificorp corn
Dean J Miller - Hand Delivery
McDevitt & Miller, LLP U.S. Mail, postage pre-paid
420 W Bannock St Facsimile
Boise, ID 83702 X Electronic Mail
[e-mail]
Tauna Christensen
Energy Integrity Project - Hand Delivery
769N 1100 E _U.S. Mail, postage pre-paid
Shelley ID 83274 - Facsimile
taunaenergyintegritvproject.org X Electronic Mail
John R. Lowe Hand Delivery
Consultant _U.S. Mail, postage pre-paid
Renewable Energy Coalition - Facsimile
12050 SW Tremont St X Electronic Mail
Portland, OR 97225
jravenesanmarcos(yahoo.com
R Greg Femey Hand Delivery
Mimura Law Offices PLLC —U .S. Mail, postage pre-paid
Interconnect Solar Development, LLC - Facsimile
2176 E Franklin Rd Ste 120 X Electronic Mail
Meridian, ID 83642
greg(),mixnuralaw.com
Bill Piske, Manager - Hand Delivery
Interconnect Solar Development, LLC _U.S. Mail, postage pre-paid
1303 E. Carter - Facsimile
Boise, ID 83706 X Electronic Mail
[e-mail]
Ronald L. Williams - Hand Delivery
Williams Bradbury, PC —U .S. Mail, postage pre-paid
1015 W. Hays Street - Facsimile
Boise, ID 83702 X Electronic Mail
[e-mail]
Wade Thomas - Hand Delivery
General Counsel _U.S. Mail, postage pre-paid
Dynamis Energy, LLC - Facsimile
776 W. Riverside Dr., Ste 15 X Electronic Mail
Eagle, ID 83616
[e-mail]
C Thomas Arkoosh Hand Delivery
Capitol Law Group PLLC _U.S. Mail, postage pre-paid
205 N 1 0th St 4th Floor Facsimile -
P0 Box 2598 X Electronic Mail
Boise ID 83701
tarkoosh(2canitollawgroun.com
CERTIFICATE OF SERVICE GNR-E-1 1-03
Brian Olmstead - Hand Delivery
General Manager _U.S. Mail, postage pre-paid
Twin Falls Canal Company - Facsimile
P0 Box 326 X Electronic Mail
Twin Falls, ID 83303
[e-mail]
Robert A. Paul - Hand Delivery
Grand View Solar II _U.S. Mail, postage pre-paid
15690 Vista Circle - Facsimile
Desert Hot Springs, CA 92241 .j Electronic Mail
[e-mail]
James Carkulis - Hand Delivery
Exergy Development Group of Idaho, LLC _U.S. Mail, postage pre-paid
802 W. Bannock, Ste 1200 - Facsimile
Boise, ID 83702 X Electronic Mail
icarkulis(exergvdevelopment. corn
Arron F. Jepson - Hand Delivery
Blue Ribbon Energy, LLC _U.S. Mail, postage pre-paid
10660 South 540 East - Facsimile
Sandy, UT 84070 X Electronic Mail
[e-mail]
M J Humphries - Hand Delivery
Blue Ribbon Energy, LLC _U.S. Mail, postage pre-paid
4515 S. Ammon Rd. - Facsimile
Ammon, ID 83406 X Electronic Mail
[e-mail]
Ted Diehl - Hand Delivery
General Manager _U.S. Mail, postage pre-paid
North Side Canal Company - Facsimile
921 N. Lincoln St. X Electronic Mail
Jerome, ID 83338
[e-mail]
Bill Brown - Hand Delivery
Adams County Board of Commissioners _U.S. Mail, postage pre-paid
P0 Box 48 - Facsimile
Council, IT 83612 X Electronic Mail
bdbrownfrontiemet.net
CERTIFICATE OF SERVICE GNR-E- 11-03
Ted S Sorenson, PE - Hand Delivery
Birch Poer Company —U .S. Mail, postage pre-paid
5203 South 11 "' East Facsimile -
Idaho Falls, ID 83404 X Electronic Mail
[e-mail]
Glenn Ikemoto - Hand Delivery
Margaret Rueger _U.S. Mail, postage pre-paid
Idaho Windfarms, LLC - Facsimile
6762 Blair Avenue X Electronic Mail
Piedmont, CA 94611
glennienvisionwind.com
margaret()envisionwmd corn
Megan Walseth Decker - Hand Delivery
Senior Staff Counsel —U .S. Mail, postage pre-paid
Renewable Northwest Project - Facsimile
917 SW Oak Street Ste 303 X Electronic Mail
Portland, OR 97205
me gan()mp org
Benjamin J. Otto - Hand Delivery
Idaho Conservation League —U .S. Mail, postage pre-paid
710 N Sixth Street (83 702) - Facsimile
P0 Box 844 X Electronic Mail
Boise, ID 83701
botto@idahoconservation org
Ken Miller - Hand Delivery
Liz Woodruff —U .S. Mail, postage pre-paid
Snake River Alliance - Facsimile
P0 Box 1731 X Electronic Mail
Boise, ID 83701
krrnller@snakenveralliance org
lwoodruff@snakenveralliance org
Robert D Kahn - Hand Delivery
Executive Director —U .S. Mail, postage pre-paid
Northwest & Intermountain Power Producers - Facsimile
Coalition X Electronic Mail
1117 Minor Ave., Ste 300
Seattle, WA 98101
rkahn(2nippc.org
CERTIFICATE OF SERVICE GNR-E-1 1-03
Don Sturtevant - Hand Delivery
Energy Director _U.S. Mail, postage pre-paid
J.R. Simplot Company - Facsimile
P0 Box 27 X Electronic Mail
Boise, ID 83707-0027
[e-mail]
Mary Lewallen - Hand Delivery
Clearwater Paper Corporation _U.S. Mail, postage pre-paid
601 W Riverside Ave Ste 1100 - Facsimile
Spokane WA 99201 j Electronic Mail
[e-mail]
A~50ams
CERTIFICATE OF SERVICE GNR-E-1 1-03