20120827Volume III.pdf

ORIGINAL
BEFORE THE IDAHO PUBLIC UTILITIES2 EO12
tr IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA QF CONTRACT ) CASE NO.
PROVISIONS INCLUDING THE ) GNR-E-11-03
SURROGATE AVOIDED RESOURCE (SAR)
AND INTEGRATED RESOURCE PLANNING ) TECHNICAL
(IRP) METHODOLOGIES FOR ) HEARING
CALCULATING PUBLISHED AVOIDED
COST RATES.
HEARING BEFORE
COMMISSIONER MARSHA H. SMITH (Presiding)
COMMISSIONER MACK A. REDFORD
COMMISSIONER PAUL KJELLANDER
PLACE: Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE: August 7, 2012
VOLUME III - Pages 264 - 439
POST OFFICE BOX 578
BOISE, IO87O1
208-336-9208 • HEDRICK
COURT REPORTING
sem+ a
APPEARANCES
For the Staff:
For Idaho Power Company:
For Avista Corporation:
For PacifiCorp dba Rocky
Mountain Power:
For Idaho Conservation
League:
For Idaho Wind Partners I,
LLC:
For The Northwest and
Intermountain Power
Producers Coalition;
Grand View Solar II;
The Board of County
Commissioners of Adams
County, Idaho; J. R. Simplot
Company; Exergy Development
Group of Idaho, LLC; and
Clearwater Paper Corporation:
For Renewable Northwest
Project; Idaho Windfarms,
LLC; and Ridgeline Energy,
LLC:
KRISTINE A. SASSER, Esq.
Deputy Attorney General
472 West Washington
Boise, Idaho 83702
DONOVAN E. WALKER, Esq.
and JASON B. WILLIAMS, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
MICHAEL G. ANDREA, Esq.
Avista Corporation
1411 East Mission Avenue
Spokane, Washington 99202
DANIEL E. SOLANDER, Esq.
Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
BENJAMIN J. OTTO, Esq.
Idaho Conservation League
710 North Sixth Street
Boise, Idaho 83702
GIVENS PURSLEY, LLP
by DEBORAH E. NELSON, Esq.
601 West Bannock Street
Boise, Idaho 83702
RICHARDSON & O'LEARY, PLLC
by PETER J. RICHARDSON, Esq.
and GREGORY M. ADAMS, Esq.
Post Office Box 7218
Boise, Idaho 83707
McDEVITT & MILLER, LLP
by DEAN J. MILLER, Esq.
4 2 0 West Bannock Street
Boise, Idaho 83702
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HEDRICK COURT REPORTING APPEARANCES
P. 0. BOX 578, BOISE, ID 83701
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For Mountain Air Projects, UDA LAW FIRM, PC
LLC: by Michael J. Uda, Esq.
7 West Sixth Avenue, Suite 4E
Helena, Montana 59601
For Renewable Energy WILLIAMS BRADBURY, PC
Coalition and Dynamis by RONALD L. WILLIAMS, Esq.
Energy, LLC: 1015 West Hays Street
Boise, Idaho 83702
For Twin Falls Canal Company, CAPITOL LAW GROUP, PLLC
North Side Canal Company, by C. THOMAS ARKOOSH, Esq.
Big Wood Canal Company, and 205 North Tenth Street,
American Falls Reservoir Fourth Floor
District No. 2: Boise, Idaho 83702
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HEDRICK COURT REPORTING APPEARANCES
P. 0. BOX 578, BOISE, ID 83701
IN DEX
WITNESS EXAMINATION BY
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William H. Hieronymus
(Idaho Power)
Lisa Grow
(Idaho Power)
Mr. Walker (Direct)
Prefiled Direct
Mr. Walker (Direct)
Prefiled Direct
Mr. Richardson (Cross)
Mr. Otto (Cross)
EXHIBITS
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266
381
383
399
434
NUMBER PAGE I
For Idaho Power Company:
6 Hieronymus Resume, 8 pgs Premark
Admit 380
For Clearwater Paper Corporation, et al:
512 "Idahoans Deserve Clean Energy At A Mark 400
Fair Price," 2 pgs
513 Request for Production No. 65, 2 pgs Mark 406
514 Agreement for Transfer of Ownership Mark 428
of Environmental Attributes, 8 pgs
HEDRICK COURT REPORTING INDEX
P. 0. BOX 578, BOISE, ID 83701 EXHIBITS
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BOISE, IDAHO, TUESDAY, AUGUST 7, 2012, 1:15 P.M.
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COMMISSIONER SMITH: All right, I think we're
back on the record. Mr. Walker.
MR. WALKER: Thank you, Madam Chair. Idaho Power
calls Dr. William Hieronymus.
WILLIAM H. HIERONYMUS,
produced as a witness at the instance of Idaho Power Company,
being first duly sworn, was examined and testified as follows:
DIRECT EXAMINATION
BY MR. WALKER:
Q. Good afternoon, Dr. Hieronymus. Could you please
state your name and spell your last name for the record?
A. William H. Hieronymus, H-I-E-R-O-N-Y-M-U-S.
Q. And by whom are you employed and in what
capacity?
A. I'm a vice president at Charles River Associates
22 International.
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Q. And did you cause to be filed prefiled direct
24 testimony of -- and one exhibit, Exhibit No. 6, in this
25 matter?
I 264 I
HEDRICK COURT REPORTING HIERONYMUS (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
A. I did the prefiled. The one exhibit I suspect is
my resume. I don't know how it was styled. But if that's it,
yes, I did.
Q. And do you have any changes or corrections to
your testimony or exhibit?
A. I do not.
Q. If I were to ask you the questions set out in
your testimony, would your answers as written be the same here
today?
A. They would, sir.
MR. WALKER: Madam Chair, I'd move to admit the
prefiled direct testimony of Williams H. Hieronymus, as well as
his Exhibit No. 6.
COMMISSIONER SMITH: If there is no objection, we
will spread the prefiled testimony upon the record as if read,
and admit Exhibit 6.
(The following prefiled direct testimony
of Mr. Hieronymus is spread upon the record.)
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HEDRICK COURT REPORTING HIERONYMUS (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
1 I. INTRODUCTION
2 Q. Please state your name and business address.
3 A. My name is William H. Hieronymus and my
4 business address is 200 Clarendon Street, T-32, Boston,
5 Massachusetts 02116.
6 Q. By whom are you employed and in what capacity?
7 A. I am a Vice President of Charles River
8 Associates, Inc., an international economics and management
9 consulting company.
10 Q. Please describe your educational background
11 and work experience.
12 A. I am an economist with a doctoral degree from
13 the University of Michigan and have spent the past 36 years
14 specializing in the economics and regulation of electric
15 utilities. I have worked extensively with utilities
16 throughout the U.S. and abroad on matters such as system
17 planning, assets valuation, rate design, procurement
18 design, risk management, load forecasting, and response to
19 regulatory policies. I have testified numerous times
20 before state utility commissions, the Federal Energy
21 Regulatory Commission ("FERC"), courts, arbitrators, and
22 legislative bodies on these topics and on policy matters
23 such as price regulation, competitive market design, market
24 power, the prudence of utility decisions, stranded costs,
25 and so forth. In the 1980s I helped utilities and
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. regulators in complying with the requirements of Public
2 Utility Regulatory Policies Act of 1978 ("PtJRPA"). This
3 included compliance with PURPA Section 210 that governed
4 purchases from and sales to qualifying facilities
5 My resume is attached as Exhibit No. 6.
6 Q. What is the purpose of your testimony in this
7 matter?
8 A. I have been asked by Idaho Power Company
9 ("Idaho Power" or "IPC") to provide an overview of
10 experience with PURPA Section 210 and to suggest lessons
11 relevant to the Idaho Public Utilities Commission's
12 ("Commission") current review and reconsideration of its
13 PURPA Section 210 implementation. While I am generally
14 aware of Idaho's recent and current PURPA implementation
15 and experience, I also recognize that Idaho PURPA history
16 is very familiar to the Commission and participants in this
17 proceeding. Hence, my focus is not primarily on the Idaho
18 experience but rather on experience with PURPA generally.
19 I also have been advised that the predominant focus
20 of this phase of the Commission's reconsideration of PURPA
21 implementation is on the methodology for computing avoided
22 costs and the application of it to QFs of different sizes
23 and types. Accordingly, my testimony focuses on avoided
24 cost methodology and its application. I also understand
25 that the scope of consideration of avoided cost does not
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1 extend to market-based methods for meeting PURPA
2 requirements, such as competitive procurements of power
3 supplies and payment of market prices as alternatives to
4 administrative/regulatory methods of setting avoided cost
5 prices. I nonetheless will discuss use of these methods
6 for two reasons. First, Idaho may choose to consider their
7 use to at least some degree. Second, the fact that such
8 methods can and have been used to satisfy the requirements
9 of PURPA Section 210 illuminates what the section requires
10 and hence provides guidance concerning what is essential
11 (and non-essential or even inappropriate) if administrative
12 avoided cost methods as designed for PURPA compliance.
13 Consistency between the requirements of PURPA and
14 state implementations of Section 210 depends primarily on
15 how avoided cost is defined and implemented. However,
16 aspects of state implementation other than avoided cost
17 calculation are at least as critical to the consequences of
18 PURPA, particularly elements of implementation that affect
19 the risk that QF payments will diverge substantially from
20 actual avoided costs for prolonged periods as well as the
21 related risk that Idaho utilities will be compelled to
22 contract for QF power in amounts that materially exceed
23 their needs. I therefore also will discuss experience with
24 and concepts relating to these other aspects of PURPA
25 implementation.
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1 Lastly, I have been asked to review and comment upon
2 Idaho Power's proposal for a new avoided cost methodology
3 to be used in Idaho.
4 Q. Could you summarize how your testimony is
5 presented?
6 A. Yes. I first will summarize my conclusions
7 and recommendations. This section also contains the
8 results of my review of the Idaho Power proposal for
9 changes from the current avoided cost methodology. Next,. I
10 will discuss the historical development of PURPA
.11 implementation and how it has changed and evolved over
12 time. I then will discuss various types of avoided cost
13 methodologies employed by different states and regions to
.14 meet the requirements of PURPA. I then make
15 recommendations regarding proper methodologies for
16 establishing avoided cost rates, and make suggestions for a
17 proper implementation of an administrative/regulation-based
18 avoided cost calculation. I also discuss other issues
19 related to power purchase agreements with PURPA QFs,
20 particularly the risk allocation and/or risk shifting
21 between the OF developer and the utility's customers which
22 relates to the length of the contractual term and nature of
23 the pricing mechanism in the contract.
24 . .
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1 II. SUMMARY OF CONCLUSIONS AND RECOMMENDATIONS
2 Q. Could you please summarize the conclusions and
3 recommendations of your testimony?
4 A. Yes. My testimony will discuss and conclude
5 that:
6 1. It is essential to not lose sight of
7 the purpose of PURPA which was limited to ending
8 discrimination against cogeneration and small renewable
9 power facilities. This limited purpose is underscored by
10 the statutory provision that prices paid shall not exceed
11 the utility's avoided cost. Not only was PURPA not meant
12 to subsidize QFs at the expense of customers, such
13 subsidies are in fact illegal if provided through PURPA QF
14 prices.
15 2. Avoiding large differences between
• 16 PURPA rates set when contracts are signed and. actual
17 avoided cost is very important. History demonstrates that,
18 overall, prices paid for PURPA power much exceeded costs.
19 This arose in part from a pro-QF regulatory bias in at
20 least some states, but also from unfortunate large errors
21. in fuel and power market forecasts. Such large errors are
22 harmful whether prices are too high or too low. The errors
23 that occurred caused high profits for developers and
24 unnecessarily high prices for consumers. Had the errors
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1 been in the other direction, ratepayers would have had a
2 windfall, at least until projects went bankrupt.
3 3. While some methods of setting avoided
4 costs are better than others and may reduce the range of
5 forecast error, no method of setting avoided cost can
6 prevent the potential for large forecast errors. The only
7 way to limit the difference between the actual value of QF
8 power and prices paid for it is to keep contracts short
9 and/or severely limit the period for which prices are
10 fixed. This can be done in a number of ways, including
11 reopeners and indexation.
12 4. The risk of getting prices badly wrong
13 is compounded by the difficulty of limiting the quantity of
14 QF power. PURPA provides no direct authority to limit QF
15 purchases to the amount and type of power that is needed.
16 However, solutions have been found that substantially
17 mitigate this open-ended obligation.
18 5. If prices paid are not only too high
19 but also higher than those paid in other jurisdictions, the
20 excess QF power seeking contracts in the high rate states
21 will be intensified. PURPA initially was focused on
22 cogeneration, which was thought to require a real host user
23 of steam and heat. Such hosts were immobile and limited in
24 number. In fact, PURPA project development has turned out
25 to be quite portable, with developers building where
271 HIERONYMUS, DI 6
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1 conditions such as avoided cost rates and contract terms
2 are most attractive.
3 6. All states, at least initially, used
4 administrative methods/regulatory proceedings to set
5 avoided costs. This was reasonable and necessary given the
6 vertical integration of utilities and the lack of
7 competitive or transparent markets for power. Unhappy
8 experience with administratively set avoided costs in the
9 early years after PURPA caused FERC and many utilities and
10 state regulatory commissions to seek alternatives,
11 primarily structured procurements such as requests for
12 proposals and "auctions" to select QF and other third-party
13 power projects.
14 7. Many states first adopted proxy unit
• 15 methods that used the cost of either the next planned
16 utility unit or a generic unit to establish avoided costs.
17 This made logical sense given that utility planning was
18 primarily driven by capacity needs. However, it led
19 increasingly to mismatches between the costs avoided by not
20 building the proxy units and the costs avoided by the QF as
21 the nature of QFs changed from primarily QFs that operated
22 like the conventional utility units used as proxies to
23 quite dissimilar plant, such as energy limited,
24 intermittent energy producers. The Idaho Surrogate Avoided
25 • Resource ("SAR") methodology is a proxy unit method.
• 272 HIERONYMUS, DI 7
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8. The other common administrative method
2 of establishing avoided cost is to use actual simulation of
3 the utility system to establish avoided cost, particularly
4 avoided energy costs. A common version uses the net-cost
5 of a peaker to establish capacity cost and simulation of
6 operation of the utility's system to establish marginal
7 energy costs. QF avoided cost rates are then based on the
8 QF's forecasted capacity contribution and the amount and
9 timing of its energy production. A more complete and
10 complex version of this methodology simulates operation of
11 the system with and without the QF. Avoided energy costs
12 is the difference "with and without" the QF; avoided
5 13 capacity costs may reflect changes in the resource plan as
14 it is adjusted to accommodate the QF. These simulation-
15 based methods are an important improvement on the proxy
16 unit method because they inherently base avoided costs on
17 the output characteristics of the QF. What Idaho Power
18 calls the Integrated Resource Plan ("IRP") methodology
19 (both currently and as proposed) is a version of this
20 methodology.
21 9. Another issue concerning PURPA
22 compliance is the use of fixed rate schedules to pay for QF
23 power. PURPA requires such schedules only for projects of
•24 100 kilowatts ("kW") or less, but many states have extended -
25 fixed offers to much larger units. In many instances, the
273 HIERONYMUS, DI 8
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1 schedule is based on a proxy unit. Use of such schedules,
2 should be sharply limited for two reasons: (a) the price
3 derived from a single proxy unit may be very
4 unrepresentative of the value of a particular QF and (b)
5 such inaccurate schedules can contribute to substantial
6 excesses of QF projects demanding contracts. This problem
7 is best mitigated by a combination of limiting the size of
8 projects that are eligible and by having multiple standard
9 offers, such that one of them reasonably corresponds to the
10 actual characteristics of the QF.
11 10. In enacting PURPA, Congress did not
12 anticipate the substantial restructuring of the utility
13 industry that took place in the 1990s. In much of the
14 country, restructuring made PURPA section 210 both onerous
15 and unnecessary.. When it enacted the Energy. Policy Act of
16 2005, which exempted utilities in regions with visible and
17 competitive organized power markets, Congress reinforced
18 that the intent of PURPA was only to assure non-
19 discriminatory treatment of QFs. The Act not only
20 eliminated PURPA obligations for utilities serving more
21 than half of the country, it also showed that Congress
22 believed that access to market prices was by itself
23 sufficient to comply with PURPA. This conclusion provides
24 important guidance on Congressional intent to those parts
25 of the country to which the exemption does not apply.
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1 11. There now are multiple ways of setting
2 PTJRPA avoided costs including two market methods: (a)
3 access to competitive power markets and (b) the creation of
4 competitive procurements, and at least two types of
5 administrative determinations: (a) proxy units and (b)
6 IRP/system simulation methods. Market methods, where
7 available and applicable, have the virtue that they take
8 the potential for bias in setting avoided cost out of the
9 equation and reduce the amount of regulatory judgment
10 required. In exempt regions, and in some other cases, a
11 demonstration of QF access to markets has been sufficient
12 to relieve the utility from all cost risks for QF power. • 13 Among administrative methods, the IRP/system simulation
14 methods have the considerable virtue that the energy
15 savings attributed to the QF are calculated directly from
16 the dispatch of the QF rather than assuming
17 counterfactually that its characteristics are those of a
18 quite dissimilar proxy unit. While more complicated than
19 proxy unit methods, simulation is within the capability of
20 all utilities and is particularly appropriate when non-
21 dispatchable, intermittent resources are a major source of
22 QF offers. The virtue of the proxy method is that it is
23 simple and relatively transparent.
24 12. My advice to the Idaho Commission
25 concerning how to set avoided costs using
275 HIERONYMUS, DI 10
Idaho Power Company
1 administrative/regulatory methods flows directly from these
2 observations:
3 a. Use avoided cost calculation
4 methods that take into account the characteristics of the
5 QF unit and accurately model the timing, dispatchability,
6 firmness and amount of power produced by the QF at issue.
7 This requires using IRP-type methods for each unit or, in
8 the case of small units, creating IRP-based standard offers
9 based on the characteristics of similar generic units. it
10 also requires time differentiation of payments.
11 b. Sharply limit the applicability of
12 fixed standard offer price schedules, which PURPA only
13 requires for QFs of less than 100 kW. If Idaho chooses to
14 extend standard offers to larger units, it is even more
15 important that multiple, technology-specific standard
16 offers be developed and used so as to avoid systematic
17 biases in avoided cost rates and unlawful discrimination
18 among QFs and between QFs and other resources.
19 C. Limit capacity payments to the
20 amount of capacity the QF actually displaces. When no
21 capacity is displaced, the payment should be zero.
22 d. Limit customers' exposure to long-
23 term price risk by such mechanisms as not offering fixed
24 prices, using formula rates indexed to actual energy or
25 fuels prices, and shortened contract lengths. It is
276 HIERONYMUS, DI 11
Idaho Power Company
particularly important that consumers not take on price
risk for QF power that is not even used to serve them, but
rather is sold into the interchange market.
e. Seek to limit purchases of
unneeded QF energy and capacity. Quantity-limited requests
for proposals ("RFP") and auctions is one way to do this.
Properly reflecting the value of the specific QFs is
another. For price rationing to work, it is necessary that
avoided costs be reset as often as is necessary to reflect
the impact of prior QF5 on avoided energy and capacity
values. Rationing based on pricing aside, this also is
necessary if avoided costs are to be computed properly.
FERC has noted that the attraction of too much QF power is
a signal that prices being paid are too high and should be
reduced. Including the successive amounts of QF power in
the calculation is one way to do this, albeit not
necessarily sufficiently.
Q. You stated earlier that you had reviewed and
would comment on IPC's proposed changes to its QF avoided
cost rates and tariff provisions. What do you conclude
based on that review?
A. I have reviewed Idaho Power's proposal for
revising the Idaho avoided cost calculation and contract
terms. My review is at a relatively high level and does
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1 not extend to some of the details in it. I conclude the
2 following:
3 1. The fact that Us in amounts well in
4 excess of what IPC can use have requested (and in many
5 cases received) long-term contracts at fixed prices
6 strongly indicates that IPC's avoided cost rates are too
7 high and need reforming. I understand further that the QFs
8 primarily have been wind farms and that most of them have
9 availed themselves of SAR-based standard contracts, which
10 indicates that the standard contract price in particular is
11 too high. I agree with IPC's conclusion that reform is
12 required urgently.
13 2. I support the proposed use of the "IRP
14 method," essentially the use of a system simulation, to
15 determine the energy price component for all QF contracts.
16 I note that IPC proposes to base technology-specific
17 standard offers on IRP analysis of generic units of each of
18 the major anticipated types of QFS. I strongly agree with
19 this approach.
20 3. The ceiling size of QFs eligible for
21 standard offers that was reduced recently from 10 average
22 megawatts ("aMW") (approximately 30 megawatts ("MW")
23 nameplate rating for wind) to 100 kW for wind and solar
24 should remain low, as IPC proposes. It also should be
25 reduced for other types of QFs, notably hydro, because
278 HIERONYMtJS, DI 13
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1 hydroelectric projects are least amenable to generic
2 surrogates. If the IPC proposal to use separate generic
3 standard.offers for the different technologies is
4 implemented, it could be appropriate to increase the
5 ceiling somewhat from the current 100 kW if it is found
6 that transaction costs of individualized rate negotiations
7 for small projects are too onerous.
8 4. Regarding the capacity element of
9 avoided cost, I support IPC's proposal to switch from a
10 combined cycle to a simple cycle peaking unit. As I shall
11 explain later in my testimony, both theory and nearly
12 universal practice in the Regional Transmission • 13 Organization ("RTQ") markets that have capacity products is
14 to base capacity values on the net capacity cost of a
15 peaker.
16 5. Regarding the energy component of
17 avoided cost, I concur with IPC that the "letter of the
18 law" of PURPA is that avoided costs are the costs that the
19 utility avoids from on-system production or power purchases
20 and does not extend to paying QFS the incremental revenues
21 that might be earned from selling the QF power or other.
22 power displaced by the QF into interchange markets. PURPA
23 requirements aside, it is poor public policy for IPC to be
24 required to enter into long-term obligations to pay QFs the
25 expected market price for power it incrementally will have
279 HIERONYMUS, DI 14
Idaho Power Company
1 to sell off system. I recognize that there may be
2 circumstances when IPC can sell QF power in interchange
3 markets for more than they will pay the QF under IPC's
4 proposal. A developer who believes it will be under-paid
5 as a QF can either develop a project elsewhere or build it
6 in Idaho but not request a QF contract, instead selling
7 into the commercial market. A further alternative is to
8 sell it to IPC under its existing non-firm QF contract that
9 pays the project the net-back price of power delivered at
10 mid-Columbia.
11 6. I also support IPC's proposal to reduce
12 the required length of QF contracts. Even if it were
13 deemed appropriate to make projects "bankable" there is no
14 reason to extend contracts beyond 10 years. Moreover,
15 there is no reason why Idaho utilities' customers should
16 take on risks that properly belong to the QF developers.
17 In my opinion, IPC is if anything being overly generous in
18 terms of the length of contract that it is proposing. The
19 contract term it is offering is longer than is available in
20 exempt markets and exceeds the length of time that Idaho
21 utilities can hedge contract obligations to buy power that
22 must be disposed of in interchange markets. The need for
23 shortened contracts also relates to the market risks that
24 customers are being required to take on. If, as IPC
25 proposes, customers are largely insulated from risks
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1 relating to on-selling OF power into interchange markets,
2 contract length is somewhat less sensitive.
3 7. The Idaho utilities currently
4 differentiate between fueled and non-fueled Us with the
5 former receiving prices that change year-by-year based on
6 actual gas prices rather than prices that were forecast at
7 the time of signing. Such an arrangement benefits both OF
8 developers and the utilities' customers since it reasonably
9 hedges the prices paid by the utilities and locks in
10 margins above fuel costs for the developers. This contract
11 form should be continued, as I understand IPC intends. The
12 benefits to customers from this form of contract are not
13 different merely because the QF is non-fueled. While IPC
14 is not proposing to extend this type of contract to non-
15 fueled QFs, I have recommended earlier in this testimony
16 that the Commission seriously consider this or other
17 changes to the form of non-fueled QF contracts to reduce
18 the risks borne by customers.
19 B. IPC is not proposing a market
20 alternative to administratively set avoided costs. Given
21 its excess energy situation, using an RFP to procure least
22 cost QF and other capacity does not seem to be a current
23 option, since the appropriate quantity in such an auction
24 would be zero. The other market option, passing market
25 prices from nearby visible competitive markets through to
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0 1 QFs in lieu of paying administratively determined avoided
2 cost rates, may or may not be consistent with PURPA
3 depending on specific facts concerning market access that I
4 have not examined. I nevertheless recommend to the Idaho
5 Commission that it examine the possible use of market
6 mechanisms as an alternative to administratively set
7 avoided costs now or at such later time as the facts
8 warrant.
9 III. PURPA. PURPOSES AND HISTORY
10 Q. What is the origin of the requirement to
11 purchase power from QF5?
12 A. The requirement originates in PURPA. PURPA
13. was one of the energy policy acts passed in the latter half
• . . 14 of the 1970s to implement the energy efficiency and
15 domestic energy supply goals of the Carter administration's
16 Project Independence. In response to the oil embargos that
17 disrupted oil supplies to the U.S. and caused both
18 shortages and several-fold increases in prices, the
19 government promulgated policies designed to reduce (with
20 the goal of total elimination) dependence on imported oil.
21 These policies included increasing domestic oil and gas
22 production, promoting the use of renewable and other
23 domestically produced energy, more efficient energy
24 conversion (e.g., in producing electricity), and more
25 efficient consumption of energy, among other things.
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Si Section 210 of PtJRPA is a relatively brief portion
2 of the bill that mandated arrangements under which electric
3 utilities would sell electricity to, and buy electricity
4 from, qualifying cogeneration and small power production
5 facilities. Section 210 tasked FERC to devise rules that
6 "it determines necessary to encourage cogeneration and
7 small power production and to encourage geothermal
8 facilities of not more than 80 megawatts capacity."'
9 Q. What guidance does the Act give FERC
10 concerning its implementation regulations?
11 A. The guidance is brief and mostly non-specific.
12 There are a few statements, however, that constrain and
13 direct FERC's implementation.
14 The portion of Section 210 dealing with purchases
15 required rules that "shall include provisions respecting
16 minimum reliability of qualifying cogeneration facilities
17 and small power production facilities (including
18 reliability of such facilities during emergencies). . .
19 The portion dealing with rules concerning rates to be paid
20 to such facilities by electric utilities:
1 FERC's implementation treated the cut-off for small power
facilities as a maximum of 80 MW. However, this misread the plain
language of the Act, a careful reading of which shows that Congress
applied the 80 MW cut off solely to geothermal. A later passage in
Section 210 dealing with exempting such facilities from being regulated
as public utilities made such exemption available to geothermal plants
of less than 80 MW and other small power facilities of less than 30 MW.
As a classic example of bootstrapping, FERC later acknowledged this,
S

but continued to apply an 80 MW limit on the grounds that this always
had been its policy.
283 HIERONYMUS, DI 18
Idaho Power Company
S
.
1 shall insure that, in requiring any
2 electric utility to offer to purchase
3 electric energy from any qualifying
4 cogeneration facility or qualifying small
5 . power production facility, the rates for
6 such purchase:
7
.8 (1) Shall be just and reasonable to
9 the electric, consumers of the
10 electric utility and in the public
11 interest, and
12.
13 (2) Shall not discriminate against
14 qualifying cogenerators or
15 . qualifying small power producers.
16
17 No such rule prescribed under subsection
18 (a) of this section shall provide for a
19 rate which exceeds the incremental cost
20 to the electric utility of alternative
21 . electric energy.
22
23 The "incremental cost of alternative electric
24 energy" was subsequently defined:
25 . For purposes of this section, the term
26 "incremental cost of alternative electric
27 energy" means, with respect to electric
28 energy purchased from a qualifying
29 cogenerator or qualifying small power
30 producer, the cost to the electric
31 utility of the electric energy which, but
32 . for the purchase from such cogenerator or
33 small power producer, such utility would
34 produce or purchase from another source.
35
36 Q. Did the Act show Congressional intent to
37. subsidize QF5?
38 A. No. It cannot be over-emphasized that the
39 intent of PURPA Section 210 was to eliminate discrimination
40 against QFs, not to subsidize them. PURPA also was
41 intended to shield QFS from being regulated like public
284 HIERONYMUS, DI 19
Idaho. Power Company
1 utilities. This shielding was perceived to eliminate cost
2 of service ratemaking as a full or partial basis for
3 pricing QF power. This eliminated the customary method for
4 assuring that prices paid were just and reasonable. To
5 avoid subsidization of QFs by utility ratepayers, the upper
6 limit on payments to QFs was set at the costs that the
7 utility would avoid as a result of receiving power from the
8 QFs. In implementing Section 210, FERC concluded that
9 avoided cost should be not only the ceiling but also the
10 floor for avoided cost computation.
11 Q. What pricing terms are available to QFs under,
12 Section 210?
13 A. The Act contemplates two classes of pricing
14 terms. First, the utility could pay the QF its avoided
15 •cost as actually avoided at the time that the QF delivered
16 power. This was the only pricing method available for QFs
17 selling "as available" non-firm power. The Act also
18 contemplates the possibility of contracts that fix prices
19 or pricing formulae at the time of signing as an
20 alternative to the payment of actual avoided costs at the
21 time of power delivery. Congress expressly found that
22 divergence 'between contractual prices and actual avoided
23 costs would not in and of itself violate the Act. It is
24 unclear whether, as a matter of law (as distinct from FERC
25 or state regulatory implementation) that the option to set
285 HIERONYMUS, DI 20
Idaho Power Company
1 prices at the time that the contract was signed had to be
2 offered. However, if it was, the QF had the unilateral
3 right to select between this form of contract and being
4 paid avoided costs calculated at the time of delivery.
5 Q. Does the Act require tariff-like standard
6 avoided cost rates for purchase contracts?
7 A. Yes, but only for very small projects. The
8 utility is required to have a standard rate for sellers of
9 less than 100 kW and may, but need not, have a standard
10 rate for larger projects. These standard rates are
11 expressly permitted to vary by type of projects.
12 Q. What do FERC's implementing regulations say
13 about these types of contractual arrangements?
14 A. The pertinent part of the regulations
• 15 ((S294.304(c) (3) (d)) distinguishes between as available
16 power sales and sales pursuant to a term contract. In the
17 former case, prices are avoided cost at the.time of
18 delivery. In the latter case, they can be set at the time
19 of contracting. FERC recognizes expressly that such rates
20 may differ, even substantially, from actual avoided costs
21 at the time of delivery. FERC gives the QF developer the
22 unilateral right to select between the two contract forms.
23 However, the regulations do not expressly require that the
24 utility offer a long-term contract with fixed prices at
25 all, so this unilateral right is contingent on the
286 HIERONYMUS, DI 21
Idaho Power Company
1 alternative being of fered.2 All of this parallels the
2 requirements of the Act.
3 What is not clear (and I pretend no legal analysis
4 of the points) is whether a contract for non-dispatchable,
5 intermittent energy such as wind is "as available" and.
6 hence is only entitled to a rate determined at the time of
7 delivery.3 Assuming that such a QF is not deemed "as
8 available" and hence is entitled to a rate determined at
9 the time of contracting, it is similarly unclear whether,
10 this can be a formula rate (e.g., one that is indexed to
11 vary with, for example, gas prices or inflation) or if the
12 utility must offer a fixed schedule of rates for the term
13 of the contract. Relevant to this point, nothing in PURE'A
14 or the regulations specifies a required length of
15 contracts. Hence, even if the QF is deemed eligible for a
16 fixed rate for the term of the contract, the utility can
17 offer only a relatively short-term contract.
18 Q. Does FERC allow non-conforming contracts?
19 A. Yes. FERC gives very wide latitude to QFs and
20 utilities to agree to whatever form of contract is mutually
21 acceptable. It expressly permits such contracts to yield
2 In RN88-06 (1988), FERC clarified that the prices offered at
signing could be formula rates, not fixed prices.
The specific language in the regulations distinguishes between
as-available power and power from QFs able "to provide energy or
.

capacity pursuant to a legally enforceable obligation for the delivery
of energy or capacity over a specified term."
287 HIERONYMUS, DI 22
Idaho Power Company
1 rates that are below full avoided cost, reasoning that the
2 QF might agree to a lower price in return for some valuable
3 non-price contract provision to which it was not expressly
4 entitled under PURPA. Conversely, such negotiated contacts
5 cannot lawfully result in prices that exceed the utility's
6 avoided costs as calculated or incurred, whichever is
7 pertinent. Thus, while PURPA and FERC's implementation of
8 it speak of encouraging cogeneration and small power, such
9 encouragement is limited by a no subsidy provision that
10 does not allow rates to be set at a level higher than the
11 utilities' incremental cost since such a rate would not be
12 just and reasonable to consumers.
13 Q. Did FERC's 1980 PURPA implementation give
14 further guidance to the states in formulating more specific
15 implementation of Section 210?
16 A. Yes. The regulations specified data that the
17 utility must provide to its state regulator(s) and directed
18 that this data should be taken into account in determining
19 avoided costs The regulations further said that rates
20 should be consistent with this data. 18 C.F.R § 292.304(e)
21 states that in setting avoided costs, "the following
22 factors shall, to the extent practicable, be taken into
23 account: . .
•1
24
•25
288 HIERONYMUS, DI 23
Idaho Power Company
ri
S i2. The availability of capacity or
2 energy from a qualifying facility
3 during the system daily and
4 seasonal peak periods, including:
5
6 i. The ability of the utility to
7 dispatch the qualifying
8 facility;
9
10 ii. The expected or demonstrated
11 reliability of the qualifying
12 facility;
13
14 iii. The terms of any contract or
15 other legally enforceable
16 obligation, including the
17 duration of the obligation,
18 termination notice
19 requirement and sanctions for
20 non-compliance;
21
22 iv. The extent to which scheduled
23 outages of the qualifying
S 24 facility can be usefully
25 coordinated with scheduled
26 outages of the utility's
27 facilities;
28
29 V. The usefulness of energy and
30 capacity supplied from a
31 qualifying facility during
32 system emergencies, including
33 its ability to separate its
34 load from its generation;
35
36 vi. The individual and aggregate
37 value of energy and capacity.
38 from qualifying facilities on
39 the electric utility's
40 system; and
41
42 vii. The smaller capacity
43 increments and the shorter
44 lead times available with
45 additions of capacity from
46 qualifying facilities; and
0 47
289 HIERONYMUS, DI 24
Idaho Power Company
1 3. The relationship of the
2 availability of energy or capacity
3 from the qualifying facility as
• 4 derived in [the methodology based
5 on i through vii] to the ability
6 of the electric utility to avoid
7 costs, including the deferral of
8 capacity additions and the
9 reduction of fossil fuel use; and
10
11 4. The costs or savings resulting
12 from variations in line losses
13 from those that would have existed
14 in the absence of purchases from a
15 qualifying facility, if the
16 purchasing electric utility
17 generated an equivalent amount of
18 energy itself or purchased an
19 equivalent amount of electric
20 energy or capacity.
21
22 Q. Did state implementations of Section 210 occur
23 soon after FERC issued its regulations in February 1980?
24 A. No. Most states were somewhat slow to provide
25 the detailed rules needed to implement Section 210. This
26 was in part due to litigation concerning the FERC
27 regulations, focused primarily on FERC's interpretation
28 that PURPA required payment of full avoided cost rather
29 than some form of benefit sharing for new QFs. Ultimately,
30 in 1982, the U.S. Supreme Court ruled that FERC's actions
31 were within its discretionary authority. While some states
32 had moved quickly, others only began the process of
33 implementation at this time.
34 State implementation of PURPA occurred primarily
35 between 1982, when litigation concerning FERC's
290 HIERONYMUS, DI 25
Idaho Power Company
1 implementation was resolved, and the mid-1980s. This was
2 an era when many state commissions were distrustful of
3 utilities' resource decisions as a result of overbuilding
4 and cost overruns for plants coming on-line during the
5 period. Some such commissions welcomed QFs in preference
6 to continued reliance on utilities building and owning all
7 new facilities.

8 Q. Recognizing that you plan to discuss how
9 PURPA has been implemented in some detail later in your
10 testimony, can you provide an overview of this initial
11 implementation?

12 A. In all cases, state implementation was based
13 on administratively determined costs. By administratively
14 determined I mean that costs were determined by
15 methodologies or formulae determined or approved by
16 regulators or legislative action rather than by observation
17 of market outcomes.4 In the early 1980s there were no
18 competitive power markets with visible prices. Almost
19 universally, utilities were vertically integrated and built
20 their own generation, so that there was little opportunity
21 to observe long-term market prices. There were no
22 independent power producers as that term came to be used in
Short-term contracts for as available power are an exception to
this generalization since such power was, per requirement of the Act,
paid the utilities actual avoided cost at the time of delivery. Even
.

this actual price was determined by methods created through regulation
since there was little if any price transparency.
291 HIERONYMUS, DI 26
Idaho Power Company
1 the 1990s. Hence, state implementation of PURPA inherently
2 involved study-based, rather than market-based, estimates
3 of avoided costs.
4 The state-by-state implementation resulted in a wide
5 range of administrative avoided cost calculation methods,
6 as I shall discuss later. Several of them certainly did
7 not take into account the factors that FERC had said should
8 be taken into account to the extent practicable and may
9 even have been facially inconsistent with the avoided cost
10 definition contained in the statute and adopted in the
11 regulations.
12 Q. Can you overview the main varieties of avoided
13 costs methods that the states adopted?
14 A. Several methods were adopted, for which the
15 two main archetypes were a proxy unit, whose capacity and
16 energy costs were used to define avoided costs, and the IRP
17 or Differential Cost method, which measured avoided costs
18 as the costs avoided as a result of contracting with the
19 specific QF in question. In addition, as a matter of law,
20 each state had a posted schedule of prices available to
21 units of no more than 100 kW, a limit extended higher and
22 even eliminated in some states.
23 Of the two methodologies, only the IRP method was
24 fully consistent with the definition of avoided costs
25 contained in the Act. However, this distinction did not
292 HIERONYMUS, DI 27
Idaho Power Company
1 appear to be important at the time and, in the minds of
2 many, did not warrant the additional complexity and
3 transactions cost of the IRP method.
4 Q. Why did the methodologies appear to yield
5 similar results?
6 A. At the time of initial state implementation,
7 the differences between the two types of methodologies were
8 not inherently large due to the nature of the QFs. Most
9 QFs were cogeneration units based on standard fossil power
10 plant designs, geothermal power, biomass (particularly, wood
11 waste in timbering areas) and municipal solid waste. All
12 of these technologies had performance characteristics that
13 were reasonably similar to the conventional utility plants
14 used as proxy units. While some wind units were built in
15 the 1980s, the technology of the day did not extend to.
16 large turbines or wind farms.5
17 Q. Was PURPA as implemented successful?
18 A. It certainly was successful in causing large
19 amounts of QF capacity to be built. However, as noted
20 previously, creating QFs was not the intent of the Act.
21 Rather, the intent was merely to eliminate discrimination
22 against them as a barrier to their construction.
23
.
The notable exception to this generalization was California.
Many thousands of small wind turbines were built in three wind farm
areas, at least partly as a result of non-PURPA state subsidies.
293 HIERONYMUS, DI 28
Idaho Power Company
1 The most obvious negative impact of PURPA was that
• 2 in some states contract rates significantly exceeded the
3 actual avoided costs when the power was delivered. This
4 arose in part because some state implementations required
5 utilities to offer avoided cost contracts of long duration
6 that also were sometimes front-loaded. These contracts
7 also contained pre-set prices. Since the Act and FERC
8 regulations provided no evident basis for limiting the
9 amount of QF power the utilities were required to buy,
10 these contracts were not, in at least some states, limited
11 to the amount of power the utilities needed.6
12 A primary reason why prices were far above avoided
13 costs was that fossil fuel prices, especially the price of
14 natural gas, fell substantially soon after most state
15 implementations. Gas was the primary fuel used by
16 cogenerators. Hence, a contract rate based on a high gas
17 price forecast not only exceeded avoided cost, it also
18 substantially exceeded the cogenerators' costs. The
19 combination of a too-high rate, long contract durations and
20 no quantity limits, led to unexpected amounts of QF
21 development, primarily in the states with such long-term
22 fixed offers. In all likelihood, the "gold rush" rapidity
6 QF development was very uneven across the country. One of the
reasons that some regions had little OF activity was that the early to
mid-1080s was a period of substantial excess capacity in much of the
country. This sometimes was reflected in lower, "energy-only" avoided
cost rates.
294 HIERONYMUS, DI 29
Idaho Power Company
1 of entry was compounded by the fear on the part of
2 developers that a too-good deal would not long persist.
3 Q. Can you provide examples of the extent to
4 which these high prices created a glut of high priced QF
5 capacity?
6 A. The two leading examples of the adverse
7 consequences of long-term fixed price offers without
8 quantity limits were California and New York. California
9 established Standard Offers 2 and 4 (September 1983) that
10 provided for fixed avoided cost rates, no limit to the site
11 of the unit built (FERC had required Standard Offers for
12 any unit below 100 kW) and allowed the QF to opt for
•,
13 levelization of payments. The offers were suspended in
14 April 1985 when it became apparent that there was neither a
15 need for the quantity of capacity (16,000 MW under contract
16 or in the contracting process in the mid-1980s) nor the
17 excess cost for the energy, estimated by Southern
18 California Edison and Pacific Gas & Electric, the two
19 largest utilities, to be $1.15 billion per year by 1990.
20 Earlier the New York state legislature had passed a.
21 law requiring that the state's utilities enter into long-
22 term contracts with QFS. The New York Public Service
See Frank Graves et al, PURPA: Making the Sequel better Than the
Original, (prepared for The Edison Electric Institute), The Brattle
Group (December 2006) on-line at:
http: //www. eei . org/what we do/Publicpoli cyAdvocacy/StateaegulatiOfl/DOCUIfle
nts/purpa.pdf, at p. 16.
295 HIERONYMtJS, DI 30
Idaho Power Company
0 1 Commission was to set the rates but was constrained to set
2 them no lower than 6 cents per kWh, well above the then-
3 current avoided costs of utilities in New York.8
4 This was argued to be acceptable because it had
5 encouraged significant quantities of QFs into the state and
6 had had little impact on the consumer price of electricity.
7 New York utilities argued (unsuccessfully) that the 6 cent
8 number was well in excess of their avoided cost with
9 Consolidated Edison stating that in 1986 their avoided cost
10 was only 3 cents and Orange and Rockland arguing it was 3.4
11 cents. Orange and Rockland went further to state that they
12 did not anticipate their avoided cost to reach 6 cents
13 until 1995.
14 The cost of excess QF power bought under the 6 cent
15 rule became manifest when New York restructured the
16 electricity industry, requiring generation divestiture and
17 retail access, among other things. Niagara Mohawk, a mid-
18 size utility, obtained regulatory permission to enter into
19 negotiations to terminate or modify its QF obligations in
20 order to quantify its excess costs that would become
8 FERC later opined that New York may have relied on a statement
that it had made in the preamble to its regulations to the effect that
states could require rates above avoided costs, notwithstanding PURPA.
However, since such rates were facially inconsistent with the express
language of the statute, the legitimacy of such rates could not rely on
PURPA. Nevertheless, New York treated the 6 cent program as PURPA
related, requiring that its utilities accept all QF power offered to
them and pay this rate.
Ibid at page 15.
296 HIERONYMtJS, DI 31
Idaho Power Company
1 stranded by the change in industry structure. It succeeded
2 in cancelling 14 of its 27 QF contracts at a cash cost of
3 $3.9 billion plus 23 percent of Niagara Mohawk equity.
4 Q. Was dissatisfaction with the results of PURPA
5 implementation limited to these two states?
6 A. No. Other states also had considerable
7 excesses of PURPA power. Many such states either suspended
8 or diminished their PURPA offers.. Others began to ration
9 QFs, along with non-QF new capacity offers by creating
10 quantity-limited procurements, with the lowest, quality-
11 adjusted offers being accepted and all others rejected.
12 Conversely, QF developers in some other states complained
13 that they were not being offered payments for capacity.
14 This dissatisfaction in both camps led to the next chapter
15 in the PURPA saga, the Congressional hearings of 1986 and
16 the FERC Notices of Proposed Rulemaking ("NOPRs") of 1988.
17 The RM-88 NOPRs
18 Q. What was the origin and subject of the NOPRs?
19 A. The substantial unhappiness with the results
20 of PURPA implementation led to hearings in both houses of
21 Congress in June of 1986. FERC responded by holding
22 regional conferences in the spring of 1987 at which various
23 parties testified concerning changes in FERC's regulations
24 implementing Section 210 that would eliminate undesirable
25 parts of state implementations. After the hearings were
297 HIERONYMUS, DI 32
Idaho Power Company
1 conducted, FERC issued three interrelated NOPRs'° in the
2 spring of 1988. These concerned: (a) the treatment of
3 independent power producers, (b) the use of structured
4 procurements to, among other things, comply with PURPA (the
5 Bidding NOPR), and (C) changes in the existing PURPA
6 avoided cost regulations (the Avoided Cost NOPR). The
7 latter two are relevant to the issues in this proceeding.11
8 Q. Were the regulations proposed in these NOPRs
9 adopted?
10 A. No. The NOPRs were very controversial at the
1.1 time. The controversy was not primarily about the changes
12 they proposed in regulations concerning avoided cost
13 pricing, but in the way in which the NOPRs proposed to
• 14 restructure the electricity industry. Much of what the
15 NOPRs proposed has since occurred. Fundamentally, the
16 NOPRs called for open transmission access, mandated but did
17 not require competitive bidding for contracts for all new
18 generation including utility provided generation that would
19 then not be subject to cost of service regulation, and
10 FERc uses NOPRs as a mechanism for eliciting comments from
interested parties concerning proposed changes in regulations.
Usually, they contain a long discussion of the issue being addressed
and a draft of the proposed new regulations. While a NOPR is not
itself a regulation, it generally contains substantial information
about how the Commission would react to particular fact circumstances.
The Independent Power Producer NOF'R proposed streamlining
regulation of a proposed new type of generators that would not be
• subject to cost of service price regulation. This presaged the
creation of Exempt Wholesale Generators in the Energy Policy Act of
1992, but has no direct relevance to the PURPA story.
298
HIERONYMUS, DI 33
Idaho Power Company
1 provisions to police self-dealing in utilities' selection
2 between affiliated and unaffiliated generation proposals.
3 Among those opposing the NOPR5 were National
4 Association of Regulatory Utility Commissioners and one of
5 the FERC Commissioners, who wrote a scathing attack on the
6 legality of the proposed changes in regulations insofar as
7 their effect was to restructure the industry. The proposed
8 regulations were quietly abandoned and FERC moved on to a
9 more gradual change in policy, beginning with Order 888 on
10 open access in 1998 and with the further changes authorized
11 or enabled by the Energy Policy Acts of 1992 and 2005.
12 Q. If the NOPRs did not change FERC's
13 regulations, why are they worth discussing?
14 A. Notwithstanding the fate of the NOPR5, they
15 provide a useful summary of problems that arose in the
16 implementation of PURPA and important information about
17 FERC's interpretation of its own regulations that, in
18 relevant part, are little changed today.
19 The Avoided Cost NOPR, RM88-6
20 Q. Did the NOPR recount comments received and
21 lessons learned in the Congressional hearings and its own
22 regional conferences?
23 A. Yes. The NOPR recounts the types of
24 dissatisfaction with the way that states had implemented
• 25 the avoided cost standard in Section 210. Overall, FERC
299 HIERONYMUS, DI 34
Idaho Power Company
1 characterized the comments as calling for moderate changes
2 and being focused primarily on the treatment of capacity.
3 FERC's description of criticisms of the implementation of
4 the portion of Section 210 regarding QF purchases by
5 utilities were organized into the following topics:
6 1. Inappropriate Methods for Determining
7 Avoided Costs.
8
9 a. Quantitative Limits on Capacity
10 Needs. FERC characterized this as the most common
11 complaint.. The 1980s were a period of substantial excess
12 capacity in much of the U.S., but utilities nonetheless
13 were required to buy energy and capacity from QFs, often
14 based on avoided cost methods that assumed a need for
15 capacity. Conversely, QF developers complained that many
16 states' implementations gave no capacity credits. The most
17 common specific complaint arose from a lack of quantity
18 limits in the requirement to sign contracts or in the
19 amount of QF capacity that would receive payments for
20 capacity. 12 FERC pointed to standard offers, extended far
21 past the 100 kW statutory requirement as one source of this
22 problem, but commented that the "committed capacity" .
12 As a lead example, FERC cited comments by Pennsylvania Power
and Light. Its state commission disallowed the entirety of its
Susquehanna 2 nuclear plant from rate base as not used and useful
because it was excess to the company's capacity requirements but then
required the company to contract for 500 MW of QFs.
300 HIERONYMUS, DI 35
Idaho Power Company
1 approach 13 and other avoided cost methods also could lead to
2 unlimited capacity commitments.
3 b. Failure to Take into Account
4 Qualitative Characteristics. In its 1980 regulations
5 implementing PURPA Section 210, FERC had listed several
6 qualitative factors that must be considered but need not be
7 taken into account in state implementations. Comments
8 criticized many of the methods used for not differentiating
9 between the characteristics of QFs and the plant used to
10 set avoided cost, using a proxy unit that is not consistent
11 with the utility's needs to set avoided costs, and not
12 differentiating among QFs in terms of characteristics such . 13 as dispatchability.
14 C. Problems When QF Capacity Offered
15 Exceeds Utility Needs. Even reasonably calculated avoided
16 costs can elicit more capacity than is needed under some
17 circumstances. This especially is true if all capacity
18 receives capacity payments. FERC also noted that some
19 states that did ration capacity payments used methods that
20 may not be efficient, such as first come, first serve.
21 d. Wholesale Sources. Proxy unit
22 methods inherently assume that avoided cost relates to the
23 cost of power from the proxy unit, whereas for many
13 The committed capacity method used the costs of either the last
unit built by the utility or the costs of the next unit proposed to be •
built by the utility as the proxy unit for calculating avoided costs.
301 HIERONYMUS, DI 36
Idaho Power Company
1 utilities, the lowest cost alternative was purchases from
2 other utilities. Further, some commenters indicated that
3 their state commissions did not understand that avoided
4 purchases could ever qualify for use in avoided cost
5 calculations.
6 2. Fixed Price Contracts. Some commenters
7 complained that fixed price, must take QF contracts
8 prevented the utility from buying substantially cheaper
9 economy energy as an alternative. Others noted that at
10 times they had to back down low variable cost baseload
11 units to make room for more expensive QF power. Still
12 others asked for guidance concerning the use of fixed
13 prices in long term contracts.
14 3. Rates Exceeding Avoided Costs. FERC
15 noted that some states had interpreted part of FERC's
16 regulations as allowing states to set PURPA rates above
17 avoided costs. The New York 6 cent minimum price, which • 18 the New York State Department of Public Service ("NYPSC")
19 Chair stated was above any of the state's utilities'
20 avoided cost, was said to be predicated on this belief.
21 FERC clarified that its intent when it earlier stated that
22 rates above avoided cost were permissible had been to point
23 out that, outside of PURPA, states could mandate purchases
24 at above avoided costs. PURPA rates, however, could not • 25 exceed avoided cost.
302
HIERONYMUS, DI 37
Idaho Power Company
1 . 4. Multistate Utilities. Utilities that were
2 jurisdictional to more than one state complained that
3 different state implementations led to different avoided
4 costs. This arose both from adoption of different
5 methodologies and from basing avoided costs on the avoided
6 costs of the subsidiary that provided service in that, state
7 rather than on the system as a whole.
8 Q. What are the major points made by FERC in the
9 avoided cost NOPR that you believe warrant emphasis?
10 A. In this NOPR, FERC clarified or emphasized
11 several matters that still bear on the setting of avoided
12 costs. One point made was that PURPA was not intended to
10 13 subsidize QFs, whatever their merits: "It should be
14 emphasized that the avoided cost standard dictates that QFs
15 should be paid consistent with, not their social value, but
16 the costs of displaced sources of power to utilities. The
17 criteria for qualification as a QF must carry the burden of
18 assuring that the QF's mode of generation is socially
19 desirable. [p.30]"
20 The Commission also stated that problems were
21 arising from avoided cost methodologies that imputed value
22 to the QF that, in fact, were phantom:
23 Inaccurate calculations of avoided
24 capacity cost appear to result in part
25 from a lack of attention to the
26 relationship between the characteristics
27 of the QFs involved and the quality,
303 HIERONYMUS, Di 38
Idaho Power Company
1 quantity, or source of the capacity
2 avoided. For utilities to use QF power
3 instead of building new plants or
4 purchasing power, it is necessary for the
5 qualitative characteristics of QFs and
6 utilities' plans to at least roughly
7 coincide. [p.35]
8
9 Several portions of the NOPR emphasize that the
10 capacity payments to be made to a QF depend critically on
11 whether the existence of the QF allows capacity to be
12 avoided. For example, "Under the Commission's current.
13 regulations, capacity payments need to be made when, and
14 only when the purchase or construction of capacity will be
15 •avoided by the purchasing electric utility as a result of
16 its purchase of QF power [p. 6]." Still more emphatically:
17 Section 292.204(c) of the current
18 regulations has been read as allowing
19 open-ended standard offers to all QFs.
20 It is clear, however, that the avoided
21 cost standard requires that QFs be paid
22 for only the capacity cost that a utility
23 avoids because of the presence of QFs
24 . . To address this problem, the
25 Commission proposes to amend . . . its
26 regulations to assure that [under] such
27 standard offers . . . capacity payments
28 would not be available once the
29 purchasing utility's capacity needs have
30 been satisfied. [p. 48].
31
32 FERC also considered the issue of the availability
33 of standard rates as opposed to QF-specific calculations of
34 avoided cost. It stated that, based on experience, it
35 proposed to raise the threshold from the statutory 100 kW
36 to a project size of 1 MW.
304 HIERONYMUS, DI 39
Idaho Power Company
0 1 In a section entitled "avoided energy costs," FERC
2 endorsed time-based differentiation of avoided energy
3 payments, recognizing that energy costs differ by season
4 and time of day.
5 Q. Did the Avoided Cost NOPR discuss the problem
6 of long-term contracts with fixed prices?
7 A. Yes. An entire section of the Order (pp. 55-
8 67) dealt with problems arising from fixed price contacts.
9 It noted that QF revenue certainty rendered via contract
10 provisions shifted risks from the OF to the purchasing
11 utility or its ratepayers. It also noted that fixed rates
12 could reduce transaction costs, which could be important
0 13 for small QFs. It made clear that its use of the term
14 "fixed price" incorporated a variety of rate types for
15 which the only common feature was that they were set based
16 on provisions contained in the contract:
17 For purposes of this proposed rule, the
18 term "fixed-Price contract" refers to any
19 legally enforceable obligation wherein
20 the rates for purchases by a utility are
21 established in advance of the time of
22 purchase. The fixed price may be a
23 single, uniform rate per kilowatt or
24 kilowatt-hour for all power, including a
25 fixed formula rate, or a complex schedule
26 of time-differentiated rates and other
27 payments. The contract's term may range
28 from decades to months. [p.56]
29
30 From this description, and in particular the
31 inclusion of formula rates, it is reasonable to interpret
305 HIERONYMUS, DI 40
Idaho Power Company
1 that the Commission was of the view that the right of a QF
2 unilaterally to select a contract based on avoided costs
3 determined at the time of the contract did not extend to
4 the right to insist on a predetermined schedule of prices
5 for the duration of the contract.
6 The Commission noted that inefficiencies arose
7 whenever rates deviated from avoided costs, since the
8 utility would be paying too much or too little. Further,.
9 when it was paying too much, this could mean that QF power
10 was being purchased and produced in lieu of lower cost,
11 more efficient power. It noted in particular the rigidity
12 . arising from non-dispatchability:
g 13 . Most of the problems with efficiency
14 associated with long term fixed-price
15 contracts flow from the rigidities such
16 contracts impose on price and quantity of
17 electricity. These problems can be
18 ameliorated by relaxing restriction on
19 price or quantity, or by shortening the
20 contract period. Quantity flexibility
21 . implies QF dispatchability. If the
22 . utility is unable to "turn the QF off" it
23 may be unable to take advantage of
24 economy energy, or it may have to back
25 down its more efficient plants to buy
26 higher priced QF energy. If the utility
27 . cannot "turn the QF on" it may not be
28 . able to take advantage of the QF's
29 capacity when it is most needed during
30 . peak demand or a system emergency.
31 [pp.61-62]
32
33 The Commission proposes to amend its
34 regulations in order to allow for greater
35 pricing flexibility. Pricing flexibility
36 may take several different forms. For
306 HIERONYMUS, DI 41
Idaho Power Company
. 1 instance a contract could provide QFs
2 with a price floor applicable to all the
3 power supplied to the utility, but still
4 provide for higher variable unit prices
5 reflecting daily or seasonal periods.
6 The price floor would provide the revenue
7 stream necessary for the QF to secure
8 financial support while the price
9 variability would induce the QF to
10 maximize deliveries in peak-load periods
11 when the utility values additional
12 supplies most. Of course, the price
13 floor should not exceed the minimum value
14 of the utility's avoided cost.
15 Similarly, a contract could provide for a
16 two part price - a fixed payment for
17 capacity and an energy price for power
18 delivered. The QF would be assured a
19 minimum revenue stream based on the value
20 of its capacity. The variable energy.
21 component would allow the utility to
22 dispatch the QF capacity only when it was
23 economic. Whatever the pattern of
24 contract payments, rates for purchases
25 from QFs should always reflect how well
26 . the characteristics of the supplier's
27 power match the purchasing utility's need
28 .
29
30 To avoid problems such as those
31 associated with take-or-pay contacts in
32 the natural gas industry, 14 the
33 Commission wishes to stress the danger of
34 including forecasted fuel costs in the
35 fixed rate structure of long-term
36 contracts, especially in combination with
37 the specification of minimum purchases
38 quantities. The Commission also
39 encourages the use of time-of-day and
14 Following partial decontrol of wellhead natural gas prices,
uncontrolled incremental prices escalated rapidly. Many natural gas
utilities signed take or pay contracts at very high prices. When
decontrol became complete, eliminating low prices for non-incremental
gas and expanded supply created a glut of gas, prices fell very
substantially. This created a regulatory problem: either contract
costs far in excess of actual costs would have to be passed through in
. rates or the excess costs would be "trapped" in the utility, leading in
some cases to bankruptcy.
307 HIERONYMUS, DI 42
Idaho Power Company
• 1 seasonal rates in flexible pricing
2 structures for long-term contracts.
3 [pp.65-66 .]
4
5 .. Q. Did the Commission express surprise at the
6 extent of the problems identified concerning the scale of
7 QF power brought about by long term contracts at fixed
8 prices?
9 A. Yes. Elsewhere in the NOPR, the Commission
10 commented that the risk that QFS would offer more capacity
11 than the utility could use had not been anticipated at the
12 time its regulations were written, but had become manifest
13 as a result of the rapid growth in QF power. It noted that.
14 in its 1980 Order it had forecasted 2,636 MW of OF power by
15 1985, whereas the amount actually installed (i.e., not
16 including contracts requested or contracts signed with
17 facilities not yet in production) was 12,120 MW.
18 Q. Did.FERC also address revenue shaping for long
19 term contracts?
20 A. Yes. One issue concerning long-term contracts
21 discussed by the Commission was the front-end loading of
22 revenues. The Commission expressed concerns about
23 intergenerational equity arising from front-end loading.
24 It also voiced a concern that, having received above market
25 prices in the early years, the supplier would walk away
26 from its contractual responsibility which could turn out to
27 be delivering power at a loss in the later years.
308
HIERONYMUS, DI 43
Idaho Power Company
1 Q. Did the Commission provide advice to states
2 concerning how to avoid attracting unneeded capacity?
3 - A. Yes. The Commission acknowledged the
4 difficulty of administratively setting avoided cost rates
5 at the proper level, such that mistakes were not always
6 avoidable. It suggested that states should monitor whether
7 their avoided cost rates were attracting unneeded QFs and,
8 if so, consider lowering them. Intriguingly, despite
9 language in PURPA and in the Commission's regulations that
10 seemed to require utilities to buy power from QFs in the
11 amounts offered, it suggested that a state that had set
12 rates that attracted too much power could suspend the rate • 13 pending its recalculation:15
14 If, in response to such a standard rate
15 or standard offer, QFs offer much more
16 capacity than the utility needs, a
17 . prospective adjustment to the rate should
18 be considered for contracts that have not
19 yet been entered into. If the excess
20 amount of offered capacity is large, then
21 the state regulatory authority or non-
22 regulated electric utility may want to
23 re-examine its method for determining
24 avoided capacity costs to see if some
25 efficient alternatives available to the
26 utility were not considered. The
27 Commission believes that if QFs offer
28 capacity in amounts greatly exceeding the
29 utility's capacity needs, then the rate
30 for purchase of that capacity was
31 probably not set in reference to the cost
32 of the utility's most efficient . 15 As I noted earlier, this suspension of a standard offer is
precisely what California had done to choke off its massive surplus of
QF offers.
309 HIERONYMUS, DI 44
Idaho Power Company
1 alternative. A rate that does not
2 reflect the cost of the utility's most
3 efficient alternative source of capacity
4 is excessive, and should be adjusted
5 downward.
6
7 Moreover, even a properly calculated
8 . standard offer will not remain
9 appropriate indefinitely. The
10 alternative upon which a rate is figured
11 comprises a certain block of capacity.
12 If this block is. fully satisfied, a
13 change in the standard offer may be
14 necessary.
15
16 The Commission recognizes the difficulty
17 of administratively setting avoided cost
18 rates that induce QFs to supply capacity
19 in amounts that exactly match a utility's
20 needs. . Obviously, the signing of
21 contracts with QFs cannot and should not
22 be postponed until a rate has been set
23 that successfully matches the amount of
24 QF power with the capacity needed by the
25 purchasing utility. . . . Rather, in the
26 event that it becomes clear that a rate
27 is eliciting more QF power than the
28 utility needs, the state regulatory
29 authorities or non-regulated electric
30 utility could .suspend the rate. [pp. 41-
31 . 42.3
32 . . .
33 Q. Did the Commission express optimism that the
34 changes it was proposing and the advice it was giving in
35 the Avoided Cost NOPR would fix the identified problems?
36 A. No. Frustration with the difficulty of
37 getting administratively determined avoided costs to
38 achieve the purposes of PURPA Section 210 led the
39 Commission to propose bidding as an alternative to
40 administratively set offers:
310 HIERONYMUS, DI . 45
Idaho Power Company
S 1 Admittedly, administratively calculated
2 avoided cost is unlikely to successfully
3 result in an equilibrium price. The
4 Commission believes that bidding is an
5 alternative that promises efficiency in
6 both determining avoided cost rates and
7 assigning avoided cost payments among
8 QF5.
9
10 The thinking behind the Commission's espousal of
11 bidding, and in particular the use of bidding as a way to
12 evade the apparent inability to refuse QF power, is buried
13 in a long footnote in the Avoided Cost NOPR:
14 The Commission has tentatively concluded
15 that purchases from other QF5 fall within
16 the meaning of "another source" under the
17 section 210(d) definition of "incremental
18 cost of alternative energy. • •" If a
19 utility does not purchase from one
20 particular OF, it certainly has the •
21 option of purchasing power from other QFS
22 . . . . Obviously, if a utility
23 purchases power from a OF at a price that
24 is higher than a rate for comparable
25 power available from another source,
26 whether it is another utility or another
27 QF, the purchasing utility's customer
28 rates would be higher than they would
29 have been had the purchase not been made
30 and the purchasing utility had purchased
31 from that other source. [pp. 35-361
32
33 The Bidding NOPR, RM88-05
34 Q. What was the purpose of the bidding NOPR?
35 A. The bidding NOPR proposed draft rules for
36 using bidding to set utilities' avoided costs for use in
37 purchasing from QFs. As stated in the introduction to the
38 NOPR:
311 • HIERONYMUS, DI 46
Idaho Power Company
1 The Federal Energy Regulatory Commission
2 (Commission) proposed to adopt regulations
3 that would authorize state regulatory
4 authorities and nonregulated electric
5 utilities to implement bidding procedures
6 as a means of establishing rates for power
7 purchases from qualifying facilities (QFs)
8 under section 210 of the Public Utility
9 Regulatory Policies Act of 1978 (PURPA). A
10 bidding program is a formally organized
11 market to acquire incremental supplies of
12 electricity. . . . This proposed rule.
13 sanctions the use of bidding as a
14 procedure for purchasing electricity for
15 purchasing electricity from QF5.
16
17 The Commission determined that bidding could
18 eliminate errors and controversy in administratively
19 determined avoided costs. In particularly, it noted that
20 some state regulators ignored whole classes of
21 alternatives, relying on a single proxy unit that may not
22 be the utility's lowest cost alternative which,
23 particularly in times of overcapacity, often is a purchase.
24 The Commission noted that states and utilities were
25 only just beginning to experiment with bidding" and that it
26 was therefore reluctant to be too proscriptive about how
27 procurements should be organized. States were free to
28 adopt bidding for some, all, or none of the utilities'
29 requirements. Moreover, while FERC uses the term "bidding"
30 to refer to the procurement methods covered by this NOPR,
16 states (page 15) that Maine, Massachusetts, and California It
had promulgated bidding rules and that Texas had a related form of
procurement. Bidding was said to be under development or at least
consideration in 14 other states, one of which was Idaho.
312 HIERONYMUS, DI 47
Idaho Power Company
.

1 it stated that a wide variety of approaches would qualify.
2 as bidding.
3 Q. What benefits were seen to arise from using
~ 0
I]
4 bidding as a method of determining avoided costs?

5 A. While using price discovery in market
6 procurements to set avoided cost was one goal of the
7 Commission's bidding proposal, it was not the only and
8 perhaps not even the main reason for advocating it. The
9 Commission stated flatly that "the purpose of bidding is to
10 determine which suppliers will receive avoided capacity
11 payments." Implicit in that statement is the presumption
12 that a state that adopted bidding would procure all of the
13 utilities' capacity needs through the bidding process,
14 notwithstanding its statements elsewhere that bidding could
15 be used to meet only part of the requirements. Non-QF
16 projects that were not selected, including projects
17 sponsored by the utilities themselves, would have no right
18 to any revenues and presumably would not receive siting
19 approval.

20 Q. Did adopting bidding mean that states could
21 avoid the utilities' open-ended obligation to buy QF power
22 at their avoided costs?

23 A. No. The Commission recognized that PURPA
24 Section 210 did not limit the requirement to buy QF power
25 to the amount that the utility needed for reliability
313 HIERONYMUS, DI 48
Idaho Power Company
purposes. However, it reasoned that the PURPA's "must buy"
requirement did not extend to paying capacity payments to
QFs that were unneeded and not selected as being economic
in the bidding procedure. Hence, while the utility still
would have to pay an administratively determined energy
payment to QFs that did not have accepted bids, the QFs
would not be entitled to capacity payments.
Left unsaid was the expectation that few QFs would
be built if they did not receive capacity payments. At the
time of the NOPR, avoided energy would typically be from
coal or gas-fired capacity (owned or purchased) and priced
at relatively low marginal costs. This would be true all
of the time if the administratively determined energy price
for QFs not selected in response to the RFP was based on a
proxy unit, and much of the time even if IRP-type methods
were used. Hence, most QF5 would earn quite little from
these avoided energy-only payments. By limiting the amount.
of capacity/energy production capability purchased via
bidding to the amount that the utility needed and limiting
the right to earn avoided capacity cost to the winning
bidders, the inefficiency otherwise inherent in the
314
HIERONYMUS, DI _49
Idaho Power Company
L
2
3
4
5
6
7
8
9
10
11
12
15
16
17
18
19
20
21
22
23
24
•25
1 statutory obligation to purchase unlimited QF energy would
2 be finessed. 17
3 Q. Did the Commission provide guidance about who
4 should be allowed to participate in bidding?
5 A. The Commission expressed a preference that
6 bidding would be "all source" bidding, with QF, Independent
7 Power Producer, and utility projects all competing
8 simultaneously. It reasoned that only an all-source
9 procurement could ensure that the least cost capacity and
10 energy was being procured. Having stated this preference,
11 the Commission then proposed that all sources could be
12 deemed to have been taken into account in a bidding
. 13 procurement even if they could not participate directly.
14 One of several ideas that it floated was that a "benchmark"
15 avoided cost could be established based on the utility's
16 IRP and the procurement would then be for resources that
17 would replace portions of it.
18 Q. Was bidding proposed to select winners solely
19 on the basis of price?
20 A. No. The NOPR stated that non-price attributes
21 could and should be taken into account in the "scoring"
" "PtJRPA imposes an absolute duty upon a utility, to offer to
purchase electric energy from QFs at rates that do not exceed the 'cost
to the electric utility of the electric energy which, but for the
purchase from such cogenerator or small power producer, such utility
would generate or purchase from another source. The Commission has
interpreted electric energy to include
.
capacity when capacity is
avoided by the utility as a result of its purchase 'from the QF."
{Emphasis added; p. 37.]
315 HIERONYMtJS, DI 50
Idaho Power Company
1 used to select winning bids. It left it to the states and
2 (where state regulators so-delegated) the utilities to
3 develop appropriate procedures.
4 Q. Was this proposal a radical change when viewed
5 from the prospective of 1988?
6 A. Yes, it was. The NOPR pre-dated the creation
7 of the class of Exempt Wholesale Generators by four years
8 and the earliest state-level restructuring of utilities by
9 about eight years. I noted earlier that the three NOPRs
10 proposed by the Commission in March of 1988 were never
11 converted into regulations. The bidding NOPR is likely the
12 primary reason for the fierceness of opposition. The
13 bidding NOPR proposed to replace cost of service regulation
14 by market based prices established in auctions. This would
15 eliminate cost-based regulation of new (and ultimately all)
16 utility-owned generation that was primarily a province of
17 state commissions. The dissenting Commissioner charged
18 that the majority was seeking to unilaterally restructure
19 the industry based on a "Genco/Disco" model of utilities,
20 where the GENCO was not price regulated, and competed with
21 similarly unregulated IPPs.
22 Q. Notwithstanding that the NOPRs were not
23 adopted, were the concepts contained therein subsequently
•24 put to use?
.25
316 HIERONYMUS, DI 51
Idaho Power Company
1 A. Yes. While this NOPR may well have been a
2 "bridge too far" in 1988, many of the core concepts in it,
3 including those that were considered most radical, were
4 adopted subsequently. The "Genco/Disco" model of industry
5 structure was already under active discussion. The model
6 was implemented two years later in the United Kingdom and
7 became the preferred template for all of the European
8 Community under regulations enacted by the Community in the
9 early 1990s. The U.S. Energy Policy Act of 1992 created
10 Exempt Wholesale Generators, independent power producers
11 allowed to compete to sell at wholesale to utilities
12 without the cost of service and other utility regulations
13 to which they previously would have been subject.
14 Several states adopted competitive bidding as the.
15 primary means of procurement shortly after the NOPR.
16 Within a decade, the "Genco/Djsco" model was adopted for
17 more than half the load-serving utilities in the country.
18 The Energy Policy Acts of 1992 and 2005
19 Q. You mentioned the Energy Policy Act of 1992.
20 What did that Act do that relates to your testimony?
21 A. The Act created a new class of generators,
22 called Exempt Wholesale Generators ("EWGs") who, like QFs
23 were exempt from utility regulation but, unlike QFs, were
24 not limited in size or fuel type. Also unlike QFs, they
25 had no right to "put" contracts to utilities. Many saw the
317 HIERONYMUS, DI 52
Idaho Power Company
1 evolution of privately sponsored generation as an
2 alternative to both QFs and a utility generation monopoly.
3 Soon after the Energy Policy Act of 1992, a number
4 of states (including those that had created the greatest
• 5 surpluses of QF contracts) began to consider deregulation
6 of the generating sector including, in many cases, the
7 divestiture of utility owned generation •(which then would
8 become EWGs). As the 1990s progressed, the development of,
9 regional transmission entities and power markets,
10 deregulation of generation pricing and investments, and
11 retail access progressed. While the California crisis of
12 2000-2001 curtailed the spread of retail access and full
13 reliance on markets to provide needed generation, the
14 restructuring of the industry already encompassed more than
15 half of the country.
16 Q. In the period after the Energy Policy Act of
17 1992, was 'there a decline in the amount of, and interest in
18 QFs.?
19 A. Yes. Generally, increasing focus on
20 reorganization of the electricity' sector, the creation of
21 RTOs and retail access put the avoided cost issue on the
22 back burner as a policy matter. The adoption of bidding
• 23 that included EWGs along with QFs as a means of procuring
24 power and meeting PURPA obligations, lower fuel prices and
•• 25 price forecasts and changes in avoided cost methodologies
318
•
• HIERONYMUS, DI 53
•
• Idaho Power Company
1 in some states made PURPA contracts less attractive for
2 developers. Indeed, the predominant PURPA issue in the
3 1990s was how to unwind uneconomic QF contracts as part of
4 electricity sector restructuring.
5 Q. What resulted from the Energy Policy Act of
6 2005?
7 A. The advent of retail access and creation of
8 regional entities with non-discriminatory transmission
9 access eliminated the basis for the anti-discrimination
10 purposes of PURPA in affected parts of the country.
11 Further, utilities that lacked retail monopolies no longer
12 had the assurance that any excess PURPA-related costs could
13 be passed through to customers. After successive attempts
14 to eliminate PURPA Section 210 in its entirety, proponents
15 convinced Congress to include amendments to PURPA in the
16 Energy Policy Act of 2005 ("EPAct"). Of greatest
17 relevance, a new Part M of PURPA exempted utilities in
18 designated RTOs)from the Section 210 purchase requirement
19 for all but small power plants. Utilities outside of these
20 RTOs were given the opportunity to demonstrate to FERC that-
21 QFs connected to them had comparable competitive access and
22 to thereby gain exemption. If this demonstration was made,
23 FERC would be obligated to exempt the utility from the
24 purchase obligation.
25
319
HIERONYMUS, DI 54
Idaho Power Company
1 The consequence of exemption is that projects that
2 would have qualified as QF5 no longer have a counterparty
3 who must buy from them. Since they have non-discriminatory
4 access to markets, in particular the spot markets of the
•

5 RTOs, the original purposes of PURPA are deemed by Congress
6 to have been satisfied and, having found that such access
• 7 exists, FERC not only could but must eliminate the QF
8 purchase requirement.
9 Q. Did EPAct cause a rethinking of avoided cost
10 methodologies?
11 A. To at least some degree. The passage of the
12 Energy Policy Act of 2005 and a requirement that FERC
• 13 implement changes in its regulations to reflect it'8
14 highlighted the limited intention of Section 210. While.
.15 EPAct only abolished the PURPA requirement in the four
16 Eastern RTOs and in ERCOT, and created an opportunity for
17 utilities in the Southwest Power Pool and in California to
18 become exempt, the criteria for exemption clarified that
19 all PUPRA required was a non-discriminatory opportunity for
20 QFs to receive market prices. This created a fresh
21. benchmark against which the avoided cost methods of other
18 There were only two changes relevant to Section 210, the only
part of PURPA dealing with QFs. A new Part M allowed utilities in RTOs
with certain characteristics to be exempt from entering into new or
renewed QF contracts and spelled out the circumstances under which
other utilities could become exempt. The new Part N eliminated QF
rights for what were usually referred to as "PURPA machines,"
cogeneration facilities for which the non-electric use was minor and
often contrived.
320
HIERONYMUS, DI 55
Idaho Power Company
1 utilities that remained subject to essentially unchanged
2 requirements to purchase QF power could be compared.19
3 Because FERC had not made major changes in its regulations
4 •since 1980, some saw EPAct as a triggering event for
5 remedying elements of the FERC regulations that had been
6 shown to cause serious problems for the industry.
7 Q. Please explain how EPAct clarified the core
8 requirements of a PURPA-compliant procurement methodology.
9 A. The EPAct provision that exempted utilities in
10 RTOs from PURPA is highly instructive of what Congress
11 considered to be the core reason for the PURPA requirement.
12 Essentially, what Congress concluded was that if a QF was
. 13 located in an RTO or similar market, then it had access to
14 a competitive market and was thereby assured of non-
15 discriminatory prices. The competitive market that is the
16 sine qua non of an RTO is a real time spot market. No RTO
17 requires any load serving entity to purchase energy
18 bilaterally on a long-term basis and the longest term for a
19 guaranteed capacity price in any RTO is three years.
20 The fact that membership in an RTO was a sufficient
21 basis for exemption therefore clarified which commonly
22 included elements of PUPRA implementation were not required
23 by the law. There is no need for "bankable" long-term
19 As implemented by FERC, the new Part M allowed other utilities
outside of the RTOs to become exempt if they could demonstrate that QFs
.

in their Balancing Authority Areas had access to competitive markets
that was at least as favorable as access to RTO spot markets.
321
HIERONYMUS, DI 56
Idaho Power Company
1 contracts or the shifting of price risk from the generator
2 to a utility. Capacity payments, which exist at all in
3 only some of the exempted markets, are not guaranteed for
4 any material length of time and are reduced substantially
5 whenever there is excess capacity. No exempt load serving
6 entity is required or expected to buy capacity or energy in
7 excess of its anticipated needs.
8 Q. You have been focusing on legislative and
9 regulatory events. Were there changes in electricity
10 markets in the last decade that also impacted PUPRA
11 compliance?
12 A. Yes. One important change was the improved
13 economics of energy limited, non-dispatchable generation
14 that qualified as QFs. Wind, and later some forms of solar
15 became significantly more economic. In the case of wind,
16 this was due to several factors: wind turbine and blade
17 technological improvements in the 1990s, a series of bills
18 in Congress that created and then extended significant
19 subsidies, additional subsidies in some states, and high
20 gas prices for much of the decade. These factors made
21 wind-powered generation approximately equal in cost to
22 conventional alternatives, at least for so long as
23 subsidies remained and gas prices were expected to remain
24 high. As in the mid-1980s, bankable contracts based on
• 25 high fuel price expectations led to a new wave of PURPA
322
HIERONYMUS, DI 57
Idaho Power Company
1 activity, with a renewed "gold rush" in geographic areas
2 with good wind regimes and/or relatively high prices for
3 PURPA power. 20 The growth of wind power has continued,
4 although substantial reductions in current and anticipated
5 gas price, the possibility of subsidies lapsing, and the
6 lack of adoption of national carbon legislation have
7 curtailed it in the recent past.
8 Q. Does the nature of these new types of non-
9 dispatchable generation have importance for how avoided
10 costs should be established?
11 A. Yes. I stated earlier that much of the first
12 wave of QFs had characteristics similar to the conventional
• 13 utility plant used in many states as a benchmark for
14 establishing avoided costs. Non-dispatchable, intermittent
15 resources have quite different characteristics. I will
16 opine later that these differences are so profound that
17 methods long used in a number of states for estimating
18 avoided costs are now categorically inappropriate.
19 IV. AVOIDED COST METHODS IN OTHER JURISDICTIONS
20 Q. You stated earlier that you would discuss the
21 various avoided cost methods in use. Please introduce this
22 section of your testimony.
23
20 While the efficient scale of wind farms approaches and may
• exceed the upper limit of PEJRPA, developers often have been allowed to
split the farms up into projects that are small enough to qualify.
323 HIERONYMUS, DI 58
Idaho Power Company
1 A. I will first discuss two studies that reviewed
2 avoided cost practices at different points in time. These
3 are an exhaustive survey of methods conducted by National
4 Economic Research Associates ("NERA"), a utility economics
5 consulting firm, in 1990 and a paper written by The Brattle
6 Group, also a utility economics consulting firm, for the
7 Edison Electric Institute ("EEl") shortly after EPAct was
8 passed in 2005. I will also discuss a sampling of state
9 methodologies in use currently.
10 1990 Survey of Avoided Cost Methods
11 Q. Please describe the 1990 study.
12 A. In 1990 NERA surveyed avoided cost
13 methodologies. They received responses from 60 utilities
14 and 49 states .
21 The results of the survey were published
15 in 1992,22 and covered both the marginal cost methodologies
16 used in setting retail electricity rates and the avoided
• 17 cost methodologies used in setting prices paid to Us.
18 While the survey is more than 20 years old, it still is
19
20
21
• 22
21 Delaware did not respond.
22 Parmesano, Hethie and Bridgman, William, The Role and Nature of
Marginal And Avoided Costs in Ratemaking; A Survey, NERA, January 1992.
324 IIIERONYMUS, DI 59
Idaho Power Company
1 representative of administratively determined avoided cost
2 methods in use today.23

3 Q. Did the survey uncover a variety of methods
4 for setting avoided costs?

5 A. Yes. As stated earlier, FERC allowed states
6 quite wide latitude in PURPA compliance, including
7 selection of methods for determining avoided costs.
8 Moreover, in some states, regulators permitted utilities to
9 devise their own methodologies, so that more than one
10 existed. Also, as in Idaho, some states employed different
11 methods for contracts of differing types or project sizes,
12 contract durations, and firmness of power deliveries.
. 13 Q. Did NERA summarize the frequency of selection
14 of the various types of avoided cost methodologies?

15 A. Yes. NERA assigned the states' avoided cost
16 methodologies into five groups, apart from "other." While
17 there were only 49 states that replied, attribution numbers
18 are larger due to states that had multiple methods. The
19 groupings were:

20 1. Least-Cost Capacity Option. Attributed
21 to 13 states. In this method, capacity value was based on
23 The exception is the use of bidding. As described previously,
bidding was sanctioned by FERC in a 1988 Notice of Proposed Rule Making
that did not ultimately become adopted into its regulations. Despite
the fact that bidding began in the late 1980s as a method of selecting
new resources and determining price levels paid to them, including QFs,
the NERA survey does not discuss any bidding-based avoided cost
methodologies.
325 HIERONYMUS, DI 60
Idaho Power Company
1 the cost of a peaker. The peaker cost was net
2 of energy profits in at least some cases .24 Generally,
3 capacity cost was not credited to the QF until capacity was
4 needed by the Utility. 25 Avoided energy was based on the
5 marginal dispatch cost of the utility, often referred to as
6 "system lambda."
7 2. Proxy Unit "A." Attributed.to 11
8 states. Capacity costs were the capacity cost of.the
9 avoided unit, sometimes but not always the next unit in the
10 utility's resource plan. Avoided energy was based on the
11 cost of energy produced by the proxy unit. This is
12 conceptually similar to the Idaho SAR methodology.
13 3. Proxy Unit "B." Attributed to six
14 states. This differs from Proxy Unit A in that any
15 capacity cost of the proxy unit that was in excess of such
16 costs for a peaker were not included in capacity value but
24 As discussed elsewhere, it is a very common practice today to
offset part of the carrying cost of the avoided cost unit with the
margins expected to be earned from sales of energy and ancillary
services. This offset was less important in the 1980s for two reasons.
First, the significant improvement in technology that markedly lowered
the heat rate for new peaking plants had not yet occurred so that they
earned little if any margin on energy relative to the utility's
marginal cost/system lambda. Second, energy margins in 1980s avoided
cost calculations were computed relative to system lambdas, not
relative to market prices as became more common after the restructuring
of the electricity industry in much of the country. If margins are
computed relative to system lambda, by definition there never is an
energy margin for the highest cost unit dispatched.
25 Excess capacity was rampant in the 1980s as a result of load
that was much lower than had be expected in the mid-1970s when
construction of long lead time, large (primarily coal and nuclear)
baseload stations was initiated. .
326
HIERONYMUS., DI 61
Idaho Power Company
1 rather were added to energy value.26 If the proxy unit is
2 indeed more economic than adding a peaker, the avoided
3 capacity cost under this method should be at or below the
4 cost if the least cost capacity (peaker) method were used.
5 4. Differential Revenue Requirements.
6 Attributed to 13 states. Avoided costs were calculated by
7 comparing the cost of the system with the QF included (but
8 treated as a zero cost resource) in comparison to the cost
9 of the system without the QF. This comparison was based on
10 the resource plan that existed if the QF did not exist.
11 This method could look similar to a least cost capacity
12 method, but if the QF merely postpones a utility unit
13 and/or if the QF is large enough to affect the utilities
14 system lambda, results will differ. Implicit in the
15 methodology, no capacity costs were included for years in
16 which capacity was unneeded. This is the method that NERA
17 attributed to Idaho in the survey.
18 5. Cost of Purchased Power. Attributed to
19 2 states. In both cases, purchased power costs were the
20 cost of economy purchases which at that time typically were
21 split-savings rates. The methodology was used only for
26 The economic theory concerning utility resource selection is
that a utility that needs capacity will build the lowest capital cost
unit (i.e., a peaker). However, it will build another type of unit
that has higher capital cost in preference to a peaker if the energy
savings value of the alternative unit justifies its higher capital
. cost. In this sense, the higher capital cost for a baseload or
intermediate unit is for the production of energy, not for capacity.
327
HIERONYMUS, DI 62
Idaho Power Company
1 non-dispatchable QFs. Both states using this method used
2 Proxy Unit A for dispatchable contracts.
3 6. Avoided Energy Cost Only (No Capacity).
4 Attributed to 15 states, including most states in the
5 Southeast. In a few cases, this treatment was limited to
6 short-term power sales, with other QF5 treated differently.
7 It is possible that the prevalence of this method in 1990
8 reflected the large amounts of excess capacity that existed
9 at that time.
10 Masked by this grouping were differences in details.
11 One category worth mentioning was the assumption about QF
12 quantities used for computing avoided energy costs.
13 Methods varied from using energy cost simulation assuming
14 no QFs, assuming the QF was in the resource mix, and (in
15 the Differential Revenue Requirements method) computing the
16 incremental cost savings either for each QF individually or
17 the savings for all QFs collectively.
18 The Energy Policy Act of 2005 and the 2006 EEl Paper
19 . Q. What was the purpose of the 2005 EEl paper?
20 A. As FERC was considering how to implement the
21 relevant parts of EPAct, the Edison Electric Institute
22 weighed in with a commissioned paper 27 that characterized
23 the types of existing methodologies, identified
27 Edison Electric Institute, PURPA: Making the Sequel Better than
. the Original, December 2006. The paper was prepared by the Brattle
Group.
328
HIERONYMUS, DI 63
Idaho Power Company
1 shortcomings and proposed changes. The passage of the
2 Energy Policy Act of 2005 and a requirement that FERC
3 implement changes in its regulations to reflect it had
4 sparked a renewed interest in avoided cost rate
5 methodologies. Because FERC had not made major changes in
6 its regulations since 1980, this was seen as an opportunity
7 to remedy elements of the FERC regulations that had been
8 shown to cause serious problems for the industry.
9 Q. What is the purpose of reviewing this paper?
10 A. This paper is a useful, albeit short, summary
11 of what had been learned about PURPA in the first 25 years
• 12 of its operation. It also provides a brief critique of the
•; 13 avoided cost methods and contracts based on that experience
14 and makes suggestions concerning how FERC could improve
15 PURPA Section 210 implementation.
16 Q. How does this paper classify avoided cost
• 17 calculation methods?
18 A. The taxonomy of administrative methods for
19 setting avoided costs discussed in the EEl study was
20 similar to that used by NERA 15 years earlier.. These were:
21 1. The Proxy or Committed Unit Method.
22. This method, also called the proxy unit method in the NERA
23 paper., assumed that the QF delayed or replaced the next
24 planned generating unit in the utility's IRP. Avoided
25 costs were therefore based on the projected capacity and
329 HIERONYMUS, DI 64
Idaho Power Company
1 energy costs for that unit. Financing cost parameters and
2 discount rates for levelization were based on the utility's
3 cost of capital. Adjustments generally included modifying
4 capacity costs to account for in-service timing
5 differences. The authors noted that the proxy unit method
6 was one of the simplest types in that it did not require
7 production cost modeling. Implicit in that simplicity,
8 however, is that the avoided costs are not modified to take
9 into account differences such as availability and capacity
10 factor between the proxy and QF unit.
11 •2. The Component/Peaker Method. This is
12 what NERA termed the lowest cost unit method. The avoided
• 13 capacity cost is the lowest cost form of capacity,
14 generally assumed to be a combustion turbine. The EEL
15 paper's description is silent on whether the capacity cost
16 was net of margins above variable cost earned in energy and
17 ancillary services markets. In fact, most of the initial.
18 adoptions of this method had no such offsets, which only
19 became important when improved turbine technology
20 substantially reduced heat rates and hence resulted in
21 operating profits for new peakers since market prices
22 and/or lambdas now were sometimes set by less efficient
23 units. The avoided energy cost is the utility's marginal
24 cost of generation over all hours of the year, but could
25 include only those hours when the QF would produce power.
330 HIERONYMUS, DI 65
Idaho Power Company
1 Implicitly, the methodology assumes that the existence of
2 the QF does not affect the utilities' marginal cost.
3 3. Differential Revenue Requirements
4 Method. In its most complex form, this method first
5 requires that the utility's expansion plan be reoptomized
6 to take into account the existence of the QF(s). The
7 existing system is then dispatched as is the reoptomized
8 system (with the QF treated as having zero costs).
9 Differential revenue requirements, including any
10 differences in capital costs, constitute the QF avoided
11 costs. This method differs from the component/peaker
12 method in that it expressly determines the avoided capacity
• 13 within the analysis and inherently reflects the dispatch
14 pattern of the QF.
15 All of these methods identified above were
16 regulatory in nature. That is, avoided cost "discovery"
17 was based on calculations made or approved as part of a
18 regulatory process rather than by observing prices in the
19 market .28 As discussed previously, at the time that PURPA
20 was adopted, utilities were vertically integrated and there
21 were no organized power markets. Indeed, it was this lack
22 of competitive options for cogeneration and small power
28 An exception is that in the component /pea ker and differential
revenue requirements methods, the market cost of purchases could be a
component if, for example, the utility had an avoidable offer of
purchased power. I shall note that Sierra Pacific had complained that
.

the Nevada Commission ignored this possibility in a proxy method
avoided cost computation.
331 HIERONYMUS, DI 66
Idaho Power Company
1 facilities that motivated Congress to include Section 210
2 in PURPA.
3 The EEl paper also discussed auction-based avoided
4 cost methods. It noted that auction-type procurements were
5 adopted largely in response to the poor performance of
6 administrative methods of avoided cost estimation. It also
7 stated that a primary reason for adopting auctions was to
8 limit the.amount of QF energy and capacity purchased and to
9 be able to select the cheapest and/or most beneficial. It
10 noted that there was a great deal of variety in how
11 procurements were conducted, particularly in how scoring
12 was done, with self-scoring of bids according to previously
13 established, transparent scoring systems being at one
14 extreme and a wholly opaque, partly qualitative
15 determination of winners by the utility at the other. The
16 paper also discussed the portions of the FERC Auction NOPR,
17 RM88-5, that discussed what types of auctions were
18 consistent with PURPA requirements. The authors also
19 stated that the auction-based procurements that were used
20 by several utilities to meet their PURPA obligations were
21 generally consistent with the NOPR, except that not all
22 embraced the proposed all-source requirements.
23
• • 24
• 25.
332 • . HIERONYMtJS, DI 67
Idaho Power Company.
1 Q. Did the paper comment on the advantages and
2 drawbacks of the various administrative methods of avoided
3 cost calculation?
4 A. Yes. The authors viewed the proxy unit method
5 as the least attractive method of determining avoided cost.
6 They noted that in many cases the proxy unit was not even
7 one that the utility would plan to build. Even if it was a
8 planned unit, the QF5 being offered and getting a price
9 based on the proxy unit's cost may be too dissimilar in
10 terms of, for example, reliability or the times when power
11 from the QF was available. They also noted that the proxy
12 unit method did not allow for reoptomizing the planned
13 system to take into account the output from QFs. This
14 proved to be a major drawback in areas where QF entry was
15 substantial in relation to the size of the utility.
16 The differential revenue requirements method and the
17 component/peaker method were regarded as more sophisticated
18 and conceptually correct, but more complex and opaque. The
19 differential revenue requirements method also is the only
20 one that models the impact of the QF on system lambda.
21 Q. Did the authors comment on the performance of
22 these administrative methods collectively?
23 A. Yes. They stated that all such methods
24 require judgment about such uncertain factors as fuel cost, • 25 cost of capital, escalation in labor and equipment costs,
333 HIERONYMUS, DI 68
Idaho Power Company
1 demand growth, and so forth. As it turned out, errors in
2 these forecasts, particularly fuel price forecasts caused
3 then-historic long-term avoided cost forecasts to be too
4 high irrespective of the method used .
29 They note rather
5 wryly that proxy methods based on coal units likely were
6 the least wrong (despite the fact that few coal units were
7 actually initiated during the period) because the estimate
8 of coal price escalation was substantially lower than
• 9 similar estimates for oil and gas and hence closer to what
10 actually transpired.
11 Q. Did the authors discuss the specific types of
12 errors that had been made in administrative avoided cost
13 approaches?
14 A. Yes. The authors grouped their comments under
• 15 six headings:
16 1. Intentionally Setting Rates Above
17 Avoided Costs. In a few cases, states deliberately set.
18 rates above avoided costs. The example they use is the New
19 York six-cent minimum that the NYPSC Chair testified to
20 FERC was well above any of the state's utilities' avoided
21 cost.
22 .
29 It should be noted that such forecast errors are not limited to
administrative methods of estimation. If participants in an auction
have a consensus of similarly incorrect expectations, auction-based • prices will be similarly wrong. The forecasting problem is not related
to the method so much as to the enormous risk of forecasting and then
fixing prices, no matter what the method.34
HIERONYMUS, DI 69
Idaho Power Company
1 2. Requiring Capacity Cost Payments Even
2 Though the Utility Does Not Need New Capacity. This was
3 discussed as primarily a consequence of standard offer
4 rates. However, the authors report that the California
5 Public Utilities Commission ("CPUC") deliberately required
•6 capacity payments when no capacity was needed to meet
7 reserve margin targets on the grounds that all capacity
8 makes at least some contribution to reliability.
9 3. Standard Offer Rates Without Quantity
10 Limits. While FERC only required standard offer rates for
11 QFs of 100 kW or iess, many states allowed standard offer
12 rates for larger projects. As noted previously, California
. 13 made its standard offer rates available to all projects.
14 Since the rates were very attractive to developers, the
15 state was swamped with projects.
16 4. Long-term Contracts with Fixed Rates.
17 As the authors had already noted, forecasts of long-term
18 prices will inevitably be wrong. While it can be hoped
19 that the errors will even out to zero, this has not been
20 the experience. While comments received by FERC in 1987
21 had argued for reopeners or other methods for limiting
22 long-term contract price risk, FERC had not acted to limit
23 the ability of states to require long-term contracts. A
24 related problem noted in the paper was the front-loading of
.25
HIERONYMUS, DI 70
Idaho Power Company
1 costs that raised intergenerational equity and out-year
2 performance risk issues.

3 5. General Errors in Avoided Cost
4 Methodology. This was a catch-all category. Two examples
5 were given. One relates to proxy unit methods where the
6 avoided cost unit was one that actually was under
7 construction. In such cases, the authors argue that the
8 sunk costs of the unit should not be included in avoided
9 cost calculations. The second example was failure to take
10 power purchase alternatives into account in setting avoided
11 costs. The example given was in Nevada; there the rate was
12 set at 6.3 cents, notwithstanding that the utility's
13 planned next addition was a firm purchase at a much lower
14 cost.

15 6. Paying the Same Rate to QFs, Regardless
16 of Their Characteristics. From the historical perspective
17 taken in the paper, this problem arose primarily from the
18 baseload-like nature of most QFs built in the earlier years
19 of PURPA. Since QF5 had the right to be paid for all power
20 generated, and prices were above the units' marginal costs,
21 these units performed like must-run baseload units. In
22 areas where quantities grew large enough, or where the
23 utility already was long baseload generation, this created
24 operational as well as financial problems for the

•25 utilities. While dispatchability had been one of the
336
HIERONYMUS, DI 71
Idaho Power Company
1 factors that FERC had expressly called for states to take
2 into account in setting avoided cost rates, in the states
3 discussed in the paper there was no price differentiation
4 for dispatchable units. Of course, this problem remains
5 since these are characteristics of wind and solar power.
6 Q. What does the report say was the response to
7 these errors?
8 A. The primary response that the paper discussed
9 was the development of competitive procurement as an
10 alternative to administrative methods. The report
11 acknowledges that this is not a panacea, since long-term
12 fixed prices can lead to serious over (or under) payment no
1 13 matter how set. Nonetheless, the authors conclude that
14 "prior to the industry disruption caused on retail
15 competition and restructuring, competitive procurement of
16 QF capacity was exhibiting promise as a means of correcting
17 some of the problems associated with administrative
18 determinations of avoided costs."
19 A Sampling of Current Avoided Cost Methods
20 Q. Thus far, you have discussed primarily the
21 avoided cost methods that were established in the 1980s.
22 Have you also reviewed some of the innovations that have
23 taken place since that time?
24 A. Yes.. I will focus particular attention On
25 California. It had one of the most painful experiences
337
HIERONYMUS, DI 72
Idaho Power Company
1 resulting from having made mistakes in PURPA implementation
2 in the 1980s and hence is likely to be mindful of lessons
3 learned.
4 I do not suggest that California is the template for
5 Idaho to follow. The California solution was a compromise
6 among interests and, like all compromises, is not perfect.
7 Further California had characteristics not necessarily
8 shared by Idaho: a large installed base of QFs coming up
9 for recontracting and a very aggressive renewables
10 requirement being two obvious examples.
11 Other states have meritorious solutions to the
12 avoided cost problem that also are worthy of consideration.
13 I will discuss a sampling, highlighting features that I .
14 believe to be of particular interest or merit.
15 Q. Please provide some background on the
16 reformation of the California methods of determining
17 avoided costs.
18 A. As discussed previously, California has very
19 substantial amounts of PURPA power. Much of that capacity
20 was signed up under Standard Offer 4 ("SO4"). SO4 fixed
21 forecasted energy prices just before gas prices-collapsed
22 and hence was highly profitable, particularly but not
23 uniquely for gas-fired cogenération. SO4 had no ceiling
24 quantity amount and, according to Southern California
25 Edison, by early 1987 caused total QF contracts in
338
HIERONYMUS, DI 73
Idaho Power Company
1 California to rise to 16,000 MW, notwithstanding that SO4
2 existed only from April 1983 until it was suspended in
3 September 1984. SO4 QFs received 10- to 30-year contracts
4 with fixed capacity payments and 10 years of predetermined
5 energy payments. The very high costs and substantial
6 amounts of capacity were illustrated in comments provided
7 to the FERC in 1987. For example, Pacific Gas and Electric
8 Company ("PG&E") testified at a FERC-sponsored regional
9 conference (memorialized in FERC Docket No. RM87-12-000)
10 that by 1990 its QF overpayments would reach an estimated
11 $857 million per year. It cited to a California Energy
12 Commission estimate made in 1986 that, as a result of its
13 QFs, PG&E would need no new capacity before the late 1990s.
14 At the time that settlement talks were underway,
15 many of the QF contracts were expiring and projects were
16 seeking new contracts, to which they were entitled under
17 PURPA. During this same time frame, California was
18 adopting numerous "green" policies, including renewable
19 quotas, such as separate utility quotas for different types
20 of renewable and cogenerated power. On the other side, in
21 implementing EPAct, FERC had invited the California
22 utilities to apply for exempt status, which would result in
23 existing QFs losing PURPA as a basis for demanding
24
• .25
339
HIERONYMUS, DI 74
Idaho Power Company
1 contracts altogether. ° This confluence of events created a
2 climate for a settlement covering utility procurement of
3 both QFs and other, non-QF cogeneration and renewable
4 power.
5 California utilities, cogeneration and combined heat
6 and power QF owners, and ratepayer advocacy groups
7 negotiated for 16 months and entered into a settlement
8 Agreement ("QF/CHP Settlement") approved by the CPUC in
9 December 2010. The QF/CHP Settlement resolved QF-related
10 disputes before the CPUC and the courts, established a new
11 QF/CHP Program in California, made available additional
12 power purchase agreement ("PPA") options for Us under the
13 QF/CHP Program, including a PURPA program for new PPAs for
14 QFs of 20 MW and smaller, and established a transition
15 phasing out QF status for QFs with greater than 20 MW net
16 output.
17 In June 2011, FERC found that the utilities in the
18 California Independent System Operator ("ISO") qualified
19 for-exemption from PURPA Section 210 purchase requirements,
20
30 In its 2006 Order, FERC determined that the exemption would not
apply, even for the five RTOs entitled to exemption, for QFs with
maximum capacities less than 20 MW. The 20 MW limit was very different
from the statutory 100 MW entitlement to a rate based on a schedule.
It is interesting that in 1987, FERC had opined that 1 MW was an
appropriate limit for exempting QFs from having to participate in all-
source procurements for states that had such methods for procuring
power. It is not clear why utilities are believed to need to serve as
aggregators for small QFs. The reason may be that the RTO membership
fees are substantial.
340
HIERONYMUS, DI 75
Idaho Power Company
1 with the exception of QFS smaller than 20 MW for which••
2 exemption had not been sought.
3 Q. Please explain the main attributes of the new
4 California procurement of cogeneration and renewable power.
5 A. The settlement has various procurement
6 mechanisms. It should be understood that the settlement is
• 7 not just about PURPA QFs, but also about non-QF renewables.
8 Under the QF/CHP settlement, a new, competitive procurement
9 process was adopted in lieu of the previous system of PUC-
10 ordered standard offer contracts. A primary mechanism
11 created in the QF/CHP Settlement is a CHP Request for
12 Offers ("RFO") process that allows the state's three large
13 utilities to run competitive, transparent RFOs for CHP
14 resources. It puts CHP resources into a process similar to
15 the competitive procurement processes that already had been
16 established for conventional resource and Renewable
17 Portfolio ("RPS") procurement. The settlement also allows
18 utilities to use non-RFO processes such as bilateral
19 contracting, renewables feed-in tariffs, a PURPA Program
20 for QFs under 20 MW, direct utility ownership, and other
21 procurement options. Allowing CHP developers to bid into
22 the RFO allows them to propose prices that are sufficient
23 to finance and develop their facilities, while at the same
24 time allowing the IOUs to pick the best offers based on a
25 number of criteria, including price.
341
HIERONYMUS, DI 76
Idaho Power Company
0 1 The QF/CHP Settlement further establishes
2 procurement "MW Targets" for each of the California IOUs
3 under the QF/CHP Program. Overall, the target is 3,000 MW
4 of new or repowered projects for the decade beginning 2010.
5 Q. Does California have a standard offer specific
6 to QFs?
7 A. Yes. The pro forma PPA for QFs of 20. MW or
8 less is available to QFs with firm or as-available capacity
9 of less than 20 MW, regardless of whether the QF has
10 submitted an offer in the RFO or seeks alternative
11 contracting options. The PPA for QFs of 20 MW or less
12 contains standard terms and conditions and incorporates the.
13 peaker-based capacity prices established in prior . PUC
14 decisions .31 For energy prices, the QF/CHP Settlement
15 establishes Short-Run Avoided Cost ("SRAC") that
16 . transitions to a market (rather than administratively
17 determined) heat rate by January 1, 2015.32 New or
18 repowered facilities must post project development security
19 and performance assurance. The term is up to 7 years for
20 existing capacity, and up to 12 years for new capacity..
31 Capacity pricing is pursuant to D. 07-09-040, with Firm
Capacity at $91.97/kW-yr and As-Available Capacity of $41.22/kW-yr
escalating each year.
32 The California Public Utilities Commission has set SRAC
energy prices using a variation of the following formula for many
years: SRAC Energy Price = Fuel Price x Heat Rate + O&M Adder. The
• regulatory heat rate in existence at the time of the settlement was in
excess of 9000 BTU/kWh, which was higher than the heat rate implied by
the market price of power.
342
HIERONYMUS, DI 77
Idaho Power Company
KI
~ 0
1 QFs of 20 MW or less are included in the Procurement MW
2 Targets for each of the California IOUs, so that while
3 there is no limit on QFs as such, the 3,000 MW overall
4 limit is in force.

5 QFs with as-available capacity receive SRAC energy
6 payments along with an as-available capacity payment. QFs
7 providing unit firm capacity also receive SEAC energy
8 payments and higher capacity payments reflect the value of
9 assured long term firm capacity.

10 The standard terms for new PURPA contracts are
11 essentially identical to the contract terms for non-QF
12 CHPs. The capacity price component is set in advance for
13 the length of the contract (12 years for new or repowered
14 capacity). The performance requirements to qualify for
15 firm capacity payments are steep: earning a full payment
16 requires an availability of 95 percent and no payment is
17 available for availabilities of less than 60 percent. As-
18 available capacity payments also are subject to non-
19 availability penalties.

20 Q. Are energy payments fixed for the duration of
21 the QF contract?

22 A. No. An important change from prior California
23 QF contracts is that energy prices are reset annually
24 rather than fixed in advance for the term of the contract.
25 The SPAC price is set based on 12 months of forward
343 HIERONYMUS, DI 78
Idaho Power Company
1 prices.33 Both capacity and energy prices are time
2 differentiated into two seasons and several time-of-use
3 periods.
4 Q. How does the QF contract treat the green
5 attributes of QF contracts?
6 A. The contracts entitle the buyer to all energy
7 and capacity from the QF as well as all of the green
8 attributes of the power production. The price, paid for
9 energy from the QF includes any greenhouse gas charges that
10 may be assessed on it based on its fuels type and
11 efficiency.
12 Q. Does California have other renewable resource
13 program specific to PURPA qualifying resources?
14 A. Yes. The Renewable Auction Mechanism, or RAM,
15 is a market-based procurement mechanism for distributed
16 renewable generation projects up to 20 MW delivered on the
17 system side of the meter. The California PUC authorized
18 the utilities to procure an initial 1,000 MW through RAN.
19 Under the market-based pricing in the.RAM, sellers compete
20 for a contract in a renewable auction mechanism, bids are
Due to a peculiarity of California law, the energy prices must
• be indexed to gas prices. Between 2011 and 2015, the heat rate used to
convert forecast gas prices to electricity prices declines to the
"market heat rate." The market heat rate is the heat rate implied by
the 12 month forward electricity prices in the relevant zone (northern
or southern California). The effect of using •a market heat rate, so
defined, is to convert the gas price formula to one that prices energy
based on the forecast electricity prices in the zone, as forecasted by
•

three separate commercial services and based principally on forward
bilateral transaction prices.
344

HIERONYMUS, DI 79
• Idaho Power Company.
1 selected by least-cost price first until the auction
•
. 2 capacity is reached. Further negotiation is not allowed.
3 The price is the as-bid price of the QF, not a market
4 clearing price for the totality of winning bids.
5 Q. Does California have a program for buying QF
6 power on the basis of schedules, as PURPA requires for
7 resources of less than 100 kW?
8 A. Yes. For smaller scale renewable resources,
9 "feed-in tariffs" are used to purchase power under.
10 predefined terms and conditions, without contract
11 negotiations or participation in a competitive
12 solicitation. Use of feed-in tariffs are restricted in
13 terms of the types of QFs that qualify to a maximum size of
14 1.5 MW and aggregate quantity (initially, less than 500 MW,
15 statewide).
16 Q. You had said earlier that California had been
17 a poster child for excess prices and quantities of PURPA
18 power in the 1980s. What are the primary areas of
19 improvement in the current California avoided cost
20 methodology?
21 A. First of all, since only projects of less than
22 20 MW are eligible for PURPA-based contracts, the
23 likelihood of great excesses of unneeded power is much
24 reduced. Second, California quit requiring utilities to
25 offer pre-determined energy prices in their long-term
345 HIERONYMUS, DI 80
Idaho Power Company
1 contracts. While contracts are up to 12 years long (a
2 shorter period than under the earlier standard offers),
3 energy prices are set only one year in advance.
4 Effectively, they are based on market energy price
5 forecasts. Prices are time-differentiated so that the
6 energy price received by the QF depends on when energy is
7 produced. Capacity prices are set at contract inception
8 for the full term, but are varied according to the firmness
9 of capacity, plant availability, and the time at which
10 energy is .produced by the QF.
11 The California QF contracts are non-discriminatory
12 in that QFs are paid on a basis very similar to non-QF
13 projects. That is, there is little advantage to qualifying
14 as a QF since essentially identical contract terms are
15 available under other state programs for non-qualifying CHP
16 and renewable power. Moreover, since the bulk of CHP and
17 renewable power is not PURPA eligible, there is no
18 impediment to the state limiting the total amount of such
19 power to that which is needed for reliability or to meet
20 other state objectives since QFs count toward the relevant
21 overall targets.
22 An exception to the lack of long-term fixed prices
23 is the program for purchases of renewable power from
24 projects of less than 1.5 MW. However, eligibility under
25 this program is severely quantity limited.
346
HIERONYMUS, DI 81
Idaho Power Company.
1 Q. Are there aspects of the California solution
2 that will pay QFs prices that are above avoided costs?
3 A. This is matter of interpretation. It had been
4 long-standing FERC policy that avoided cost had to be set
5 with reference to all potential sources of power. This was
6 applied specifically to California in a FERC order in case
7 EL95-16-001. This decision found that a CPUC order
8 requiring utilities to buy QF power in an auction process
9 in which participation was limited to QFs violated PURPA,
10 since prices determined in such an auction could exceed
11 prices available from non-QF alternatives. By this
12 standard, the renewables-only auctions in the current
13 California scheme can result in overpayments.
14 However, as part of revisiting PURPA and renewables
15 development that I have just discussed, the CPUC petitioned
16 FERC for determination of whether feed-in tariffs and other
17 mechanisms limited to QF5 violated PURPA. In EL10-64-001,
18 FERC essentially reversed its earlier order. It reasoned
19 that when a state had a renewable portfolio standard, power
20 from sources that do not qualify as renewable cannot be
21 used to meet the requirement. Hence, the lowest cost
22 available resource that qualifies as renewable is the
23 avoided cost for meeting the RPS requirement. Hence, a
24 competition restricted to renewable resources can validly
.• 25 set an avoided cost that is consistent with PURPA.
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0 1 From this I infer that the mechanisms created in
2 California for estimating the PURPA avoided cost for
3 renewables that allow payments greater than made to non-
4 renewables are lawful, at least in California. However,
5 their validity would seem to depend on the existence of a
6 bright line renewable resource procurement requirement with
7 firm and specific renewable resource quotas and based on
8 the EL110-64-001 would seem to be valid only under those
9 circumstances.
10 Innovations in Various Other States
11 Q. What is the purpose of this section of your
12 testimony?
13 A. While I have discussed the categories of
14 avoided cost methods, there are important details within a
15 type of method that Idaho may wish to consider. I have
16 reviewed several different avoided cost methodologies and
17 extracted some of the features of them.34
18 Q. What is the first topic you will discuss?
19 A. The first topic is the use of visible market
20 prices for calculating avoided costs.
21 As I discussed previously, the Energy Policy Act of
22 2005 mandated that utilities in the five original RTOs were
Reviews were either from original source documents or from
summaries contained in a 2011 study sponsored by the Southern Alliance
for Clean Energy, authored by a Ms. Carolyn Elefant, titled "Reviving
PURPA's Purpose: The Limits of Existing State Avoided Cost Ratemaking
.

Methodologies in Supporting Alternative Energy Development and A
Proposed Path for Reform," available at www.carolynelefant.com .
HIERONYMUS, DI 83
Idaho Power Company
1 eligible for exemption from PURPA section 210 altogether.
2 Hence, projects that previously would have been QFs in
3 those areas are dependent on either bilateral contracts
4 with utilities or the visible markets conducted by the RTOs
5 for revenue. Most such contracts are short run in nature;
6 state-supervised auctions typically are for three years or
7 less. RTO power markets are even shorter term, with prices
8 varying even within the hour and prices set at most a day
9 ahead. Capacity typically is bought on a monthly,
10 seasonal, or annual basis in those RTOs that have capacity.
11 markets.
12 Power markets are also used in several instances to
13 set avoided cost rates where the utility is not exempt.
14 California is one example. Energy prices for QFs except
15 the smallest ones are set based on one year forward market
16 prices. Other states using market prices for at least some
17 QFs include utilities in RTOs in the period prior to
18 exemption, for which Massachusetts is an example,
19 Southwestern Public Service ("SPS"), which is in an RTO but
20 is not exempt, Oregon, which uses market prices for energy
21 when .a utility does not need capacity, and Progress Energy-
22 Carolinas, that offers market prices as an option that a QF
23 can select.
24
.25
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Idaho Power Company
1 Q. How did Massachusetts set avoided cost prices
2 prior to the blanket PURPA exemption for ISO-New England
3 utilities?
4 A. Massachusetts was one of the earliest states
5 to restructure. Its utilities sold their generation and
.6 bought their provider of last resort power from ISO
7 markets. These same markets were available to all power
• 8 suppliers,including QFs. When Massachusetts utilities
9 still had obligations to purchase from QFs under PURPA,
10 they were allowed to satisfy the obligation by taking title
11 to the power, and paying the ISO-NE spot energy price at
12 the QFs location for power, as well as the locational price
13 for capacity set in the ISO-NE market.
14 Q. Please explain how SPS uses market prices to
15 set avoided costs.
16 A.. SPS is a member of the Southwest Power Pool
17 ("SPP"). SPP utilities did not qualify automatically for
18 exemption, but FERC invited its members (similarly to the
19 • CAISO member utilities) to apply for exemption. SPS and
20 two other SPP member utilities applied jointly for
21 exemption in 2008. While the other two utilities gained
22 exemption, FERC found that QFs in SPS might not have
23 sufficient access to markets to cause FERC to grant an
24 exemption. SF5 continues, therefore, to be required to buy
25 QF power under PURPA. However, both the Texas and Oklahoma
350 HIERONYMUS, DI 85
Idaho Power Company
1 state regulators have concluded that SPS can meet its PURPA
2 responsibilities by buying power from the QFs and paying
3 them the price they would receive if they sold into the SPS
4 balancing market. The reasoning is that the sole cause of
5 SPS being denied exemption is because of market access
6 concerns, not concerns over the appropriateness of market
7 prices as measures of avoided costs. SPS's agreement to
8 pay the market price irrespective of whether the power
9 could be delivered outside of its BAA solved the market
10 access problem.
11 Q. flow does Oregon use market prices to set
12 avoided costs?
13 A. Oregon distinguishes between avoided cost
14 methods for near-term periods when utilities have
15 sufficient resources to meet reliability requirements and
16 longer term periods when new resources are needed. Oregon
17 uses the proxy methodology for the future, resource deficit
18 periods. It uses monthly on-peak and off-peak forward
19 prices as of the time of contract signing for the near
20 term, resource adequate period. No capacity payment is
21 made during that period.
22 Q. How are market prices used in North Carolina?
23 A. In North Carolina each utility has its own
24 primary method for setting avoided costs. Both the peaker
25 and IRP methods are permitted. Progress Energy uses the
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1 IRP method. It offers standard contracts for units up to
• 2 five MW (three MW for hydro) with the standard contract
3 based on a generic version of the QF type (e.g., solar,
4 municipal waste, or wind). As an alternative, the QF can
5 elect to be paid the locational marginal price calculated
6 by the Pennsylvania-Jersey-Maryland ("PJM") RTO at its
7 interconnection with Progress Energy. This is somewhat
• 8 different than for SPS and the Massachusetts utilities
• 9 since Progress Energy is not in PJM. Rather, PJM is used
• 10 as the closest market with a competitively set, visible
11 market price.
12 Q. Do you have any examples of utilities using
13 auction or RFP methods to set prices?
14 A. Yes. An example is Georgia using competitive
15 bidding to set its avoided costs. The RFP quantity is
.16 based on the utility's needs. All QFs of five MW or more
17 must bid in response to the RFP and receive a contract only
18 if they are winning bidders. Smaller QFs can get the RFP
• 19 price without participating.
20 Q. Can you provide any examples of creative
21 approaches using administrative methods for setting avoided
22 costs?
23 A. Yes. Florida uses the next unit proxy unit
24 method. What differentiates Florida from most other states
. 25 using the method is that it is quite literal about using
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Idaho Power Company
1 the utility's next unit as the proxy, in that the proxy
2 unit is changed in response to changed circumstances,
3 including contracting with QFs.
4 Each utility must identify the next avoidable unit
• 5 in its resource plan. Avoided capital costs are based on
6 the savings from deferring the unit, essentially the annual
7 carrying costs, escalating at the construction cost
8 escalation rate. If the avoided unit is on line well into
9 the future, capital cost payments can begin at a time
10 before the on-line date of the avoided unit, reflecting the
11 need to commit resources to its construction if it is not
12 avoided. Avoided energy costs are the energy costs of the
13 avoided unit beginning when the avoided unit would have
14 come on line. For periods before the on-line data of the
15 avoided unit, only as-available energy payments are made.
16 These are the ex post actual avoided costs arising from all
17 of the QFs that are receiving as-available rates, averaged
18 over the block of all such capacity. This is not the
19 system lambda for two reasons. First, this averaging will
20 reduce the energy price relative to a system lambda.
21 Second, the calculation is made after first eliminating the
22 energy used to serve interchange sales. That is, only the
23 cost of energy that is avoided in meeting native load
24 counts, as available QFs do not receive the higher cost of
25 energy that only is generated to make off-system sales.
353 HIERONYMUS, DI 88
Idaho Power Company
1 Q. Does the Florida QF offer system include
2 tariff-like standard contracts?
3 A. Yes. These are available only to units of 100
4 kW or less. The regulations appear to contemplate that all
5 other contracts are negotiated. The utility is not
6 required to pay more than its avoided costs and must
7 negotiate in good faith. The Commission may order the
• 8 utility to sign a contract and penalize dealing in bad
9 faith.
10 Q. Can Florida utilities limit the amount of QF
11 capacity that they purchase?
12 • • A. Not directly, but there are specific
13 mechanisms to change (lower) the price when sufficient
14 capacity has been contracted.
15 Q. How does this mechanism work? •
16 A. The proxy unit used to set avoided cost is a
17 specific planned unit with defined capacity. The standing
18 offer to QFs arising from the avoidance of that unit closes
19 whenever an RFP to actually construct that unit is issued,
• 20 when the amount of capacity needed to fully displace that
21 unit has been contracted, or when the unit is removed from
• 22 the utilities' resource plan for other reasons..
23 Closing the old offer triggers a new avoided cost
• 24 based on what becomes the utilities avoided unit.
• 25 Necessarily, this unit will have a later on line .date than
• 354 •
HIERONYMUS, DI. 89
Idaho Power Company
1 the unit ' that previously had set avoided costs. Usually
2 this new avoided cost will be less attractive to QFs, if
3 for no other reason because the period of time that will
4 pass during which the QF receives no capacity payments and
• 5 receives only ex post short run incremental cost for energy
• 6 will be longer.
7 Q. What lessons do you draw from these examples?
8 A. From the examples of non-exempt utilities
9 basing payments on actual market prices, I infer that this
10 practice is acceptable to FERC and to at least some state
11 regulatory commissions. From the Georgia example, I note
12 that utilities still can rely on competitive procurement
I 13 for limited quantities of energy and reject QF offers
14 (other from small units) that do not win in the
15 procurement. From the Florida regulations, I see that even
16. proxy unit methods can result in limiting QF energy
17 purchases and, at least in principle, avoid buying unneeded
18 capacity or paying more than avoided costs. The Florida
19 example also is interesting in its treatment of QF energy
20 received before the avoided unit would have been on-line
21 and in its exclusion of interchange sales in setting short
22 run avoided cost of energy.
23
H 24 . .
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Idaho Power Company
Si V. CURRENT AVOIDED COST OPTIONS AND RECOMMENDATIONS
2 FOR IDAHO'S AVOIDED COST METHODOLOGY
3 Characterization of Types of Methods
4 Q. You have discussed various methods of
5 calculating avoided cost at some considerable length.
6 Would you please very briefly restate what categories of
7 methods exist?
8 A. Presently there are two types of methods of
9 determining avoided costs: administrative/regulatory
10 determination and market revelation. Each can, in turn, be
11 divided. To summarize:
12 1. Administrative/Regulatory.
13 a. Proxy Unit. There are several
14 variants on this method; the core is that avoided costs are
15 based on the capital costs and variable operating costs of
16 a proxy unit which may be the next unit in the utilities
17 resource plan, and commonly is a combined cycle or
18 combustion turbine unit.
19 b. System simulation/IRP. The pure
20 variant of this method requires injection of the QF into
21 the utility's preferred resource plan, then reoptomizing
22 new builds and resimulating system cost. Avoided cost is
23 the difference between the two streams. A simpler version
24 assumes that the next unit would have been a peaking unit
25 and computes the capacity value of the QF based on the
26 capital cost of the peaker, preferably calculated net of
HIERONYMUS, DI 91
Idaho Power Company
1 energy and ancillary services net revenues and adjusted for
2 the on-peak availability of the QF. The QF's energy
• 3 avoided cost is, as with the pure variant, based on
4 simulation of marginal energy costs for the utility, but
5 assuming that the incremental costs without the QF will
6 also be the incremental costs when it is on-line.
7 2. Market Discovery.
8 a. RFP/Auction. The utility holds
9 competitive procurement for a defined amount of power. The
10 price set in the procurement is the utility's avoided cost,
11 though non-price •factors can be taken into account in
12 selecting winners. The price usually is available to QFs
13 only if they are winners in the auction. While FERC
14 favored all-source procurements for such procurements, its
15 recent EL10-64-001 decision (discussed in connection with
16 California's avoided costs) allows auction arrangements
17 limited to certain kinds of resources such as wind or solar
18 under defined circumstances.
19 b. Market Pricing. This effectively
20 is the substitute for avoided cost pricing and contracts in
21 areas where PURPA exemption is available. As discussed in
22 connection with SPS's Oklahoma and Texas tariffs, and
23 Progress Energy's North Carolina's tariff, it also can be
24 used where QF access to markets cannot be assured, but
.25
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Idaho Power Company
1 relevant competitive markets can be used as a benchmark for
2 pricing PURPA power.
3 Q. Which of these methods currently is used in
4 Idaho?
5 A. My understanding is that Idaho currently uses
6 the proxy unit in its SAR methodology for smaller units and
7 the simpler version of the system simulation/IRP method for
8 larger units.
9 Discussion of Avoided Cost Calculation Methods
10 Q. You have discussed four types of methods of
11 determining avoided costs. Is there a hierarchy in terms
12 of how well they comport with the basic PURPA requirement
13 that prices be at, but no higher than, the utility's
14 avoided cost?
15 A. Market-based solutions are congruent with this
16 requirement, almost by definition. Whether a price can be
17 readily observed, as in the RTO5 spot markets, or must be
18 discovered, as in the structured procurement method,
19 depends on where the utility is located. While a case can
20 be made, and FERC at one time made that case, that market-
21 based solutions are better than even the best
22 administrative solution, market forecasts are simply
23 consensus forecasts and have no per se claim to superiority
24 over a properly conducted forecast made in the course of
•25
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HIERONYMUS, DI 93
Idaho Power Company
1 the utility's business or conducted as part of a regulatory
2 or administrative process. 35
3 Setting aside issues of convenience and
4 transparency, which may be controlling for very small QFs,
5 the preferable administrative method is the IRP method.
6 The proxy unit method is clearly inaccurate, at least under
7 today's circumstances. Various forms of the proxy unit
8 method were initially the most commonly adopted. The
9 virtue of the proxy method is simplicity and transparency.
10 The method does not require forecasting the operation of
11 the utility's system, but only the operating cost of the
12 proxy unit. A single schedule of prices is derived and
16 13 available for application to all QFs. This simplicity is
14 also its Achilles Heel. Quite simply, it ignores the fact
15 that different types of QFs have very different operating
16 characteristics and hence allow the utility to avoid very
17 different costs. This particularly is true of intermittent
18 resources such as wind and solar and non-dispatchable
19 and/or energy limited resources such as some hydroelectric
20 facilities. I understand that these are likely to be the
21 most common types of QFs in Idaho in the near future.
22
FERC's claim of superiority for auction methods of setting
prices did not rest on the assumption that auction participants were
better forecasters than utilities or regulators, but on the observation
that if the utility actually purchased the lowest cost power offered to
.

it, it was paying a proper avoided cost price for the product that was
the subject of the auction, at least at that time.
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HIERONYMUS, DI 94
Idaho Power Company
0 1 Q. How are today's circumstances different from
2 those that existed when most states adopted some form of
3 proxy unit method?
4 A. There is a much greater mismatch between the
5 characteristics of a proxy unit and the types of units
6 being offered as QFs. A proxy unit anywhere in the U.S.
7 most likely would be a gas-fired combustion turbine or a
8 gas-fired combined cycle unit. Compared for example, to a
9 wind farm, these types of units have excellent reliability
10 and availability and hence value as capacity, and the
11 ability to provide important ancillary services. Combined
12 cycle units also are economic producers of energy much of
13 the time, whereas the energy value of combustion turbines
14 is limited as a result of high dispatch costs. Conversely,
15 a wind farm has very little capacity value due to the high
16 proportion of time when it cannot produce energy and a lack
17 of diversity to other wind units, little if any positive
18 ancillary services value and, indeed, impose integration
19 costs arising primarily from the •need for the utility to
20 carry additional regulation. On the other hand, its energy
21 production value typically is substantially greater than
22 the combustion turbine and may be greater than a combined
23 cycle unit where wind regimes are favorable and combined
24 cycle units are uneconomic for significant portions of the
25 year.
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HIERONYMUS, DI 95
Idaho Power Company
1 Q. Is it possible to adjust the proxy unit-
2 derived avoided cost to create a reasonable estimate of the
3 avoided costs applicable to the types of units that are
4 seeking PURPA contracts?
5 A. To some degree, yes. For example, the
6 capacity value of the QF can be adjusted from the proxy
7 unit to reflect different availability. However, there
8 still are important other differences that should be
9 reflected in avoided cost but will not be. Use of a common
10 proxy unit also distorts the relative avoided cost of
11 different types of QFs. For example solar power produces
12 energy that is disproportionately during high load periods
S 13 but wind does not.
14 It could be argued that there is a place for a proxy
15 unit for the rate schedule used for small QFs. This is the
16 practice in Idaho, where the SAR-derived schedule is based
17 on a proxy unit. However, using a single type of proxy
18 unit still results in the same proportionate distortion as
19 if the proxy unit method were applied universally. The
20 size limit merely confines the damage.
21 Fortunately, there is no need to use a proxy unit,
22 even for the published rate schedules that must be made
23 available for small units. There is not, and never was, a
24 requirement for a single rate schedule for small QFs, much • 25 less a single proxy unit. Instead, the set rate schedules
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HIERONYMUS, DI 96
Idaho Power Company
1 can be developed separately for each of the main types of
2 QFs. My understanding is that in Idaho these are wind
3 power, irrigation-based hydro, and solar. Basing the rate
4 schedule for wind QFs on a generic wind unit's avoided cost
5 and a solar schedule on a generic photovoltaic unit's
6 avoided cost, for example, greatly improves the accuracy
7 and non-discriminatory nature of the schedules. A set of
8 rate schedules that computes avoided costs with reference
9 to the operating characteristics of generic units of the
10 differing QF technologies makes use of the system
11 simulation/IRP method instead of the proxy unit method.
12 This is an element of the IPC proposal in this proceeding.
13 Q. Skipping over the system simulation method
14 which I understand to be the primary focus of your
15 recommendations, what are the virtues of the market-based
16 methods?
17 A. Congress has determined that access to
18 transparent and liquid markets achieves the goals of PURPA.
19 This is reflected in the exemption of utilities in
20 organized RTO markets from PURPA Section 210 obligations.
21 Similar access to a liquid and transparent market outside
22 of an RTO should be similarly sufficient to achieve the
23 intended non-discriminatory effect. In the Idaho context,
24 the closest transparent and visible market price is the
25 mid-Columbia price. If the state's utilities were to pass
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Idaho Power Company
1 through revenues that were based on the mid-Columbia price
2 (with appropriate power firming, system integration, and
3 transmission cost adjustments), the resultant avoided costs
4 would be identical to the revenues that the QF would
5 receive if Idaho were part of a market in which utilities
6 qualify for exemption. This pricing could be done on an ex
7 post basis. It also could be on an ex ante basis for up to
8 two or three years (as is the case in Oregon), since
9 reasonably thick and liquid markets exist for that period.
10 Access to these forward markets permits both price
11 discovery and an opportunity for the utilities to hedge
12 their price commitments. If done on an ex post basis, this
S 13 is essentially the result that would ensue if the Idaho
14 utilities were exempt. The ex ante solution provides the
15 QF with somewhat greater price certainty, without unduly
16 burdening customers with price risks.
17 Q. Do you believe that this type of price
18 discovery would be found by FERC to be consistent with
19 PURPA, even if the Idaho utilities are not eligible for
20 exemption?
21 A. Most likely, yes, but this is not entirely
22 certain, particularly since the current FERC strongly
23 promotes renewable generation and demand response as
24 alternatives to fossil generation. But on the merits, it
• 25 should be acceptable. Under this option, the market
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HIERONYMUS, DI 98
Idaho Power Company
1 pricing of QF power is non-discriminatory, in that the QF
2 gets a price based on the market price of power at which
3 the Idaho utilities can and do buy and sell non-QF power.
4 It also assures that Idaho ratepayers are not disadvantaged
5 by paying more for power than they would pay non-OF
6 sources. If, as it likely must be, market pricing is
7 either ex post or based on forward markets that do not
8 extend far into the future, it can essentially eliminate
9 long-term contract risks.
10 Q. What would your response be to the argument
11 that these short-term, market-based prices may not be high
12 enough or firm enough to cause QFs to be built?
• 13 A. Quite simply, that PURPA never was intended to.
14 subsidize QFs. If the prices that utilities can buy power
15 for in markets are too low to support a particular QF or
16 type of QF, it is entirely consistent with PURPA that the
17 QF is not built. Regarding the firmness of prices, it
18 simply is not the case that long-term firm prices are
19 . required in order to get QFs or, for all that, non-QF
20 merchant capacity built. A "bankable" contract makes it
21 easier and cheaper to get high leverage project finance.
22 However, nothing in PURPA mandates that customers should
23 shoulder the price risks that make cheap financing
24 available, especially since the reduced financing cost is
25 not flowed through to them in lower power costs..
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HIERONYMUS, DI 99
Idaho Power Company

S i Q. Are •there reasons why it might be preferable
2 to use the second type of market pricing, the RFP, or
3 action method?

4 A. The primary virtue of this type of procurement
5 is that it can be tailored to acquire the types of capacity
6 that the particular utility needs. Such procurements can,
7 and have, given weight to the various factors that FERC
8 said from the beginning of PtJRPA should be taken into
9 account, such as firmness, dispatchability, fuels
10 diversity, and so forth. I recognize that a procurement
11 that seeks to weight these various non-price factors
12 quickly becomes complex and arguably somewhat arbitrary,
S 13 but there is now a considerable body of experience that
14 could guide the development of such a methodology.

15 From a QF's perspective, a virtue of the RFP•/auction
16 process is that the QF sets its own bid level.
17 Necessarily, the price set in the RFP is commercially
18 acceptable, at least to the winners. By the nature of the
19 procurement, QFs that can or will only accept higher prices
20 will not be selected. Importantly, by limiting the
21 quantity procured to the amount that the utility actually
22 needs, the process shields ratepayers from the •risk of
23 paying what may be excessive amounts for power that is not
24 needed and cannot be resold for the contract costs.
•25
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HIERONYMUS, DI 100
Idaho Power Company
r
~ 0

• 1 The RFP/auction method is best applied if there is a
2 need for new power supplies. While it might be possible to
3 have an energy-only auction when no capacity is needed,
4 this is not likely to attract the entry of new suppliers.
5 My 'understanding' is that at least some Idaho utilities do
6 not presently need new capacity beyond that already on-line
7 or under construction and that IPC is also long energy
8 under normal water conditions in almost all time periods.

9 Q. You have shown support for market-based
10 methods of setting avoided cost. Are there reasons why
11 Idaho might validly chose an administrative method?

12 A. I have suggested that simply paying market
13 prices might not be acceptable to FERC and that the
14 RFP/auction method is of questionable applicability in the
15 face of excess capacity and energy. I also recognize that
16 movement to market-based methods would be a very large
17 change from Idaho's current practices. In my experience,
18 regulation usually changes on a more evolutionary, basis.
19 Hence, while I believe that the market solutions merit
20 serious consideration in Idaho, I observe that this is not
21 the current expectation as is shown by the fact that this
22 proceeding is focused on improving Idaho's avoided cost
23 calculation methods using methods other than 'market price
24 discovery.
25
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HIERONYMUS, DI. 101
Idaho Power Company
. 1 VI. SUGGESTIONS CONCERNING AVOIDED COST PRICING
2 BASED ON ADMISISTRATIVE METHODS
3 Q. Assuming that the Idaho Commission wishes to
4 continue to set avoided costs administratively, what
5 suggestions to you have?
6 A. My first suggestion is that it should rely on
7 the IRP-type of calculation. I make the following
8 suggestions for the how the IRP-type of avoided cost
9 calculation could be conducted:
10 1. Avoided cost calculations should be
11 based on the specific characteristics of the QF, not on the
12 costs of a proxy unit.
13 2. •Set schedules should be made available
14 for only small units. Avoided costs for these schedules
15 for smaller resources should be based on IRP analyses for
16 generic versions of that type of resources. At a minimum,
17 Idaho should have generic avoided costs for wind,
18 photovoltaic solar, cogeneration (and other baseload fueled
19 projects), and irrigation-based hydro.
20 3. Calculations of energy value should be
21 based on the latest available information, not frozen for
22 extended periods. Offering prices based on non-current
23 forecasts will cause either a flood or dearth of offers
24 depending on the direction of changes.
25 4. The model used to forecast energy
26 prices should be updated as appropriate to reflect the
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HIERONYMUS, 01. 102
Idaho Power Company
1 amount of QF capacity that is in process. Additions of QF
2 capacity that are must-take or inframarginal, as is the
3 case for the types of QFS being offered in Idaho, displace
4 higher cost units and hence result in lower system marginal
5 costs. Including previously contracted QFs in the model
6 used to predict avoided energy costs makes avoided cost
7 calculation more current and accurate and has the salutary
8 effect that if a glut of QFS materializes due to too
9 favorable avoided cost offers, the resultant drop in prices
10 should help to moderate the glut.
11 5. For quite large increments of capacity
12 (either individual projects or aggregates of projects), the
13 effect of the resource on marginal costs and the need for
14 capacity should be taken into account. This suggests an
15 IRP-type of "with and without" simulation rather than the
16 static "without" simulation to determine energy costs that
17 is adequate and appropriate for small QFs.
18 6. If Idaho retains long-term or even
19 intermediate-term contracts with predetermined prices, it
20 is important that customers not take on price and
21 marketability risks for power that is not economically or
22 operationally useful on the utility's system. PURPA does
23 not require that off-system sales revenues be factored into
24 avoided costa and it is improper for customers to shoulder
25 such risks for power that does not benefit them.
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Idaho Power Company
0 1 7. The capacity cost component of avoided
2 cost should be based on the cost of the resource with the
3 lowest net cost, net cost being computed based on its fixed
4 costs offset for net contributions earned from providing
5 energy and ancillary services, if any. Normally the
6 correct unit will be a simple cycle combustion turbine,
7 though in some circumstances it has been shown to be a
8 different type of unit.36
9 8. The appropriate maximum project size at
10 which fixed schedules are offered to QFS (presently, 100 kW
11 for wind and solar and 10 aMW for other types of QFs)
12 should be kept low, especially if Idaho continues to use a
13 single SAR-based schedule for small QFs. Conversely, it
14 may be reasonable to somewhat relax the size limit if the
15 single SAR schedule is replaced by multiple, IRP-based
16 generic schedules for the individual types of QFs.
17
36 As explained previously, the cheapest form of capacity (other
than, perhaps, some forms of demand response) is a simple cycle peaker.
However, other units may be cheaper forms of capacity if their higher
cost is more than off-set by their higher value in producing energy and
ancillary services. The three northeastern RTOs, which have capacity
markets, derive the starting point for determining a capacity price
based on the "net cost of new entry." This is the annual fixed cost of
the unit, minus the difference between the revenues it would earn for
selling energy and ancillary services and the variable cost of
providing them. At times, this revenue offset has been large enough
for combined cycle units that they have been the new entry, unit, since
their net cost is below the net cost of the peaker. I also noted
previously that capacity costs used for avoided cost purposes sometimes
do not offset costs with energy and ancillary services value. This is
conceptually wrong, but may be acceptable factually where and when
peakers earn negligible margins, conversely, where old and inefficient
.

units are marginal much of the time, in New York City for example, the
offsets are quite important.
369
HIERONYMUS, DI 104
Idaho Power Company
1 9. All calculations need to take into
2 account whether the utility needs, or even can absorb the
3 energy and capacity from the QF. If QF procurement cannot
4 be cut off entirely when no resources are needed, avoided
5 costs should reflect the lack of need. At a minimum, the
6 capacity value component of avoided cost should be adjusted
7 to reflect a low to zero capacity value for unneeded
8 capacity.
9 Q. In your discussion of the lessons learned from • 10 PURPA experience, you stated that the most important source
11 of excess costs being imposed on utility customers came
12 from large amounts of power purchased under long-term
41 13 contracts at prices that were fixed at levels that turned
14 out to substantially exceed avoided costs. Do you have any
15 recommendation concerning contract length?
16 A. Yes. Long-term contracts with prices,
17 particularly energy prices, set for long durations should
18 be avoided. PURPA does not require that contracts of any
19 particular term length be offered. However, if long-term
20 contracts are offered, the QF gets to choose whether it
21 wants to be paid avoided costs computed at the time of the
22 contract or avoided costs computed at the time of delivery.
23 PURPA and the FERC regulations also are silent on
24 the type of price offer that must be made at the time of • 25 contracting. • The long-term offer, if made, presumably
370
HIERONYMUS, DI 105
Idaho Power Company
1 could be either a fixed schedule of prices or a formula
2 rate (as FERC suggested in the Avoided Cost NOPR). A
3 formula rate could, for example, be wholly or partially
4 indexed to gas prices. Indeed, my understanding is that
5 the current Idaho avoided cost rates for fueled projects
6 are of this nature. Clearly, a formula rate linked to the
7 cost of the power purchases or fuel that is actually
8 avoided due to QF purchases is both more appropriate under
9 PURPA and less risky for customers.
10 Q. QF developers contend that long-term contracts
11 are essential since without assured revenues, the projects
12 cannot be financed. If long-term fixed prices are not
13 offered, does this mean that no one will build QFs in
14 Idaho?
15 A. Not necessarily. It is not actually true that
16 non-utility generation, including QFs, will not be built
17 without long-term contracts with fixed prices. There are
18 numerous examples of EWGs that are financed and built
19 without such contracts. Indeed, some are being built in
20 the exempt regions without bilateral contract support.
21 What is actually complained of by developers is that the
22 lack of such contracts raises financing costs. A secure
23 and predictable revenue stream allows new facilities to be
24 project financed with high leverage and low debt costs. In
25 effect, the utility signing such a contract is absorbing
371
HIERONYMUS, DI 106
Idaho Power Company
0 1 the financial risks of the project by guaranteeing a
2 revenue stream that may greatly exceed actual value or, at
3 .a minimum, is substantially more certain than the
4 fluctuating value of energy in today's volatile power
5 markets. Project risk is thus shifted from the developer
6 and lenders to the utility and its shareholders and
7 ratepayers. For QFs (and distinct from EWGs), the risk is.
8 shifted entirely to ratepayers since, by law, prudently
9 incurred costs of PURPA power must be passed through in
10 rates.
11 PURPA does not require, and I can think of no
12 justification for, Idaho utilities' customers absorbing the
13 risks that lenders to QFs arguably will not. The risk that
14 long-term fixed prices may prove to have been substantially
15 mis-forcast is the greatest problem with PURPA
16 implementation. Long-term contracts at predetermined
17 prices are the main reason why many contracts signed in the
18 1980s resulted in windfall gains for developers and
19 excessive cost for ratepayers. Fuel prices had been
20 expected to continue to escalate, but actually declined. I
21 note that Idaho, at the time, adjusted its contract terms
22 to reflect this lesson. The contract term for Idaho
23 standard offers was reduced from 35 to 20 years in 1987 to
24 reduce this forecast uncertainty. It subsequently was
. 25 reduced to 5 years. In 2002, the maximum contract term was
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Idaho Power Company
1 increased back to 20 years, notwithstanding that then-
2 recent experience demonstrated the huge risks involved in
3 setting prices based on forecasts of fuels prices over long
4 periods. 37
5 As I have discussed, the perception in the 1980s
6 that contract prices were well above market and likely to
7 be reduced as regulators lowered fuels forecasts
8 contributed to a gold rush of unneeded power, exacerbating
9 the cost impacts on mis-forecasting. A similar situation
10 appears to be occurring now, as gas prices forecasts have
11 been lowered and then lowered again and again as
12 forecasters have come to better understand the impact of
. 13 new technology for recovering shale gas on gas supplies and
14 prices.
15 Q. Are there other reasons why Idaho is
16 vulnerable today to too-high prices for QF power?
17 A. Yes. For certain types of resources, some
18 areas of the country are much better than others. Wind,
19 solar, and small hydro are obvious examples. To focus on
Idaho avoided cost rates for non-fueled projects that were in
effect just prior to Decision 29124 in 2002 were assumed to increase by
6 percent per year from a base of $5.23/mmBTtJ. In that decision, the
forecast was reduced to an escalation rate of 2.6 percent from a base
of $3.75/mmBTU. Obviously, such a difference has an enormous impact.
The fuel cost of the 7100 BTU heat rate unit adopted in that proceeding
for the proxy unit would escalate to $66.4 per MWh in 10 years based on
the then-preexisting assumptions versus $33.4/Mwh under the new
assumptions. After 20 years, the fuel costs would be $118.4/MWh under
.
the prior assumptions and $44.8/Mwh under the assumptions adopted in
2002. Current fuels prices and forecasts suggest that even the lower
of these forecasts was too high.
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Idaho Power Company
1 wind, the best wind regimes are primarily in the Pacific
2 Northwest and northern Midwest (and to a lesser degree, the
3 northeast) and in areas like Oklahoma and the Texas
4 panhandle. An examination of installed wind power
5 demonstrates that Idaho has in the past been only one of
6 several good locations. However, most of the states
7 mentioned as good wind regimes, outside of the Pacific
8 Northwest, are now exempt from PURPA. Developers seeking
9 PURPA contracts have much narrower markets. The exemption
10 of utilities in previously attractive markets may be one
11 reason for the surge of contract requests in Idaho in 2010.
12 Q. If the avoided cost rates and contract terms
0 13 offered in Idaho are made less attractive, what will
14 happen?
15 A. This depends partly on what happens in other
16 states. QF developers today are essentially balance sheets
17 looking for profitable investments, wherever they can be
18 found. If Idaho offers lower prices and/or less attractive
19 contract terms than other states, QF developers may choose
20 to build in those states. This is not necessarily a bad
21 thing. A state that pays too much for QF power will not
22 only overpay, but also attract unneeded capacity. This is
23 the strong lesson learned from the New York and California
24 experiences in particular. The large amount of QF power
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HIERONYMUS, DI 109
Idaho Power Company
• 1 tendered to IPC suggests that it may be a recent lesson for
2 Idaho.
3 Q. Does eliminating long-term fixed prices only
4 protect customers?
5 A. No. As events unfolded in the past, fuel
6 costs were much lower than the forecast costs embedded in
7 fixed contract prices, so that contracts were very
8 profitable to developers who bought cheap gas and sold
9 power at prices that had been set assuming expensive gas.
10 However, had events been different, with gas prices well
1.1 above the forecasts fixed into contracts, the roles would
12 have been reversed. The cogenerators who sold at fixed • 13 prices would have had to buy gas at prices well in excess
14 of the prices implicit in the QF energy price. Such QFs
15 easily could have lost money on every kWh generated and
16 would have soon been bankrupt.
17 Q. What do you suggest is the appropriate way to
18 treat contract length and firmness?
19 A. Contract lengths should be quite limited if
20 fixed prices are used. One possible limit is the length of
21 time for which Idaho utilities can hedge the value of the
22 power that they purchase by engaging in off-setting
23 bilateral sales contracts elsewhere. This would be
24 particularly appropriate if, contrary to what IPC is
25 seeking to achieve with its proposal, the Idaho utilities •
375
HIERONYMUS, DI 110
Idaho Power Company
.
1 are required to contract for QF power that they do not need
2 and will have to sell into interchange markets during much
3 of the contract term with customers taking the price risk.
4 A still short, but somewhat longer, contract term could be
5 appropriate for QFs that actually can be absorbed by the
6 host utility's load.
7 Contract length can be limited directly, or by
8 limiting the period of time for which prices are firm. If
9 the firm period is less than contract length, the contract
10 can specify how prices will be reset in the future.
11 Q. Is it the case that short contracts create
12 stranded asset risks for developers, in that the developer
13 may not have a customer to whom power can be sold once the
14 contract is over?
15 A. That is a theoretical risk, and may not even
16 be merely theoretical for EWGs that do not have access to
17 competitive markets. However, so long as Idaho utilities
18 are not exempt from PURPA Section 210 obligations, their
19 obligation to buy the output of QFs remains. A QF with an
20 expiring contract is entitled to a new contract from its
21 interconnected utility.
22 It is possible that changed circumstances or federal
23 law may cause the Idaho utilities to become exempt from
24 PtJRPA Section 210 responsibilities sometime in the future.
25 However, under PURPA as modified by EPAct, exemption
376
HIERONYMUS, DI 111
Idaho Power Company
• 1 requires satisfying FERC that QFs will have access to a
2 competitive market into which they can sell power.
3 Exemptions therefore will not be granted if there is any
4 material risk that QF assets will be stranded.
5 Q. Are you as concerned about fixing long-term
6 prices for capacity as you are for energy?
7 A. No. Technological change and changes in
8 financing costs can create a mismatch between avoided
9 capacity cost estimates and outcomes .38 However, building
10 new, long-lived utility plant always entails these risks.
11 Moreover, the variability in outcomes for capacity cost and
12 value are considerably less than for energy.
• 13 Q. If the Idaho Commission decides that it wants
14 to require long-term QF contracts with terms set at the
15 time of signing, what terms can be used to limit risks to
16 the utilities' customers?
17 A. Fixing terms at the time of signing does not
18 necessarily require fixing prices. Other than provisions
19 calling for periodic resetting of prices, the obvious
20 alternative for reducing customer risk is price indexation.
21 One option is to index prices to power prices in adjacent
22 markets. I have discussed instances where this is done.
The previous footnote illustrated the change in Idaho avoided
cost parameters relating to fuels markets in 2002. In comparison,
fixed costs relating to capacity were little changed, with the capital
cost of the combined cycle unit declining somewhat in real terms and
the fixed operations and maintenance rate increasing somewhat.
377
HIERONYMUS, DI 112
Idaho Power Company
.
1 An alternative which is only modestly less useful is to
2 index energy prices at least partly to natural gas prices.
3 Prices in Northwest energy markets are, at least much of
4 the time, based on prices into California. In turn,
5 California prices are set based on the cost of gas most of
6 the time, other than during the spring run-off affecting
7 Northwest and California hydroelectric generation. For
8 this reason, indexing contract energy costs to actual gas
9 prices reasonably assures that contract prices will not
10 diverge greatly from the value of power in the marketplace
11 and the prices at which Idaho utilities buy and sell power
12 in northwestern markets, at least in periods other than . 13 times of peak water flow.
14 For the gas-fired cogenerators that historically
15 were the bulk of QFs, indexed prices also reduced rather
16 than increased risk since fuel-indexed rates caused energy
17 payments to track their fuel costs, locking in capacity-•
18 related margins that pay most of construction-related
19 costs. However, indexation does not protect margins for
20 the non-gas fired generators that are the primary source of
21 recent QFs in Idaho.
22 Q. Do you have any concluding comment on how
23 PURPA avoided costs should be set and contracts formulated?
24 A. Yes. Consistency with the letter, and intent • 25 of PURPA Section 210 requires state implementations with
378
HIERONYMUS, DI 113 .
Idaho Power Company
I
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2 consistent with the letter and intent of PURPA. If Idaho
1 two, and only two consequences: assuring that Us are not
2 discriminated against, and protecting customers by limiting
3 payments to be no higher than the utility's avoided cost.
4 PURPA was not, and is not, intended to guarantee that QFs
5 will be profitable, or even that they will be built.
6 It is likely that resetting prices to reflect lower
7 fuel price escalation expectations and the existence of
8 excess capacity in the state and reducing the scope of
9 price guarantees will result in lower amounts of QF power
o being offered in Idaho than has been offered in recent
1 years. This is an appropriate outcome and is fully
time?
A. Yes, it does.
379
6 including, for example, set-aside procurements limited to
7 renewables such as were approved in the past year for
B California.
9 Q. Does this complete your testimony at this
HIERONYMUS, DI 114
Idaho Power Company
S
10 1 3 determines that it needs more renewable generation than
I4 PTJRPA produces, there are other policy tools that can be
1. 5 used to cause renewable generation to be constructed,
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(The following proceedings were had in
cross-examination.
COMMISSIONER SMITH: Thank you.
Mr. Andrea, do you have questions?
MR. ANDREA: No, Madam Chair.
MR. SOLANDER: No questions.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: No questions, Madam Chair.
COMMISSIONER SMITH: Ms. Nelson.
MS. NELSON: Madam Chair, no questions for me.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: No questions, Madam Chair.
MR. MILLER: No, thank you.
MR. UDA: No questions, Madam Chair.
COMMISSIONER SMITH: Williams.
MR. R. WILLIAMS: No questions.
MR. ARKOOSH: No questions, Madam Chair.
COMMISSIONER SMITH: Ms. Sasser.
MS. SASSER: No questions, Madam Chair.
COMMISSIONER SMITH: Any questions from the
Commissioners?
HEDRICK COURT REPORTING HIERONYMUS (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
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open hearing.)
(Idaho Power Company Exhibit No. 6 was
admitted into evidence.)
MR. WALKER: And Dr. Hieronymus is available for
COMMISSIONER REDFORD: No.
COMMISSIONER SMITH: No redirect.
COMMISSIONER KJELLANDER: Nice to see you.
MR. WALKER: No redirect, Madam Chair.
COMMISSIONER SMITH: Thank you for coming to
Boise.
(The witness left the stand.)
MR. WALKER: Madam Chair, may Mister -- may
Dr. Hieronymus be dismissed?
COMMISSIONER SMITH: If there's no objection, he
may be excused from the remainder of the proceedings.
MR. WALKER: Idaho Power calls Lisa Grow as its
next witness.
LISA GROW,
produced as a witness at the instance of Idaho Power Company,
being first duly sworn, was examined and testified as follows:
DIRECT EXAMINATION
BY MR. WALKER:
Q. Could you please state your name and spell your
last name for the record?
A. My name is Lisa Grow. Last name is spelled
G-R-O-W.
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HEDRICK COURT REPORTING GROW (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
Q. And by whom are you employed and in what
capacity?
A. I'm employed by Idaho Power Company as the senior
VP of power supply.
Q. And did you previously file a written direct
testimony in this matter?
A. I did.
Q. And do you have any changes or corrections to
that testimony here today?
A. I do not.
Q. If I were to ask you the questions set out in
your prefiled direct testimony, would your answers be the
same?
A. They would.
MR. WALKER: Madam Chair, I'd move to admit the
testimony of Lisa A. Grow and have it spread upon the record.
COMMISSIONER SMITH: Seeing no objection, we will
spread the prefiled testimony of Ms. Grow upon the record as if
read.
(The following prefiled direct testimony
of Ms. Grow is spread upon the record.)
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HEDRICK COURT REPORTING GROW (Di)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
1 Q. Please state your name and business address.
2 A. My name is Lisa A. Grow and my business
3 address is 1221 West Idaho Street, Boise, Idaho 83702.
4 Q. By whom are you employed and in what capacity?
5 A. I am employed by Idaho Power Company ("Idaho
6 Power" or "Company") as the Senior Vice President of Power
7 Supply.
8 Q. Please describe your educational background
9 and work experience with Idaho Power.
10 A. I graduated from the University of Idaho in
11 1987 with a Bachelor of Science degree in electrical
12 engineering. I received an Executive Masters of Business
. 13 Administration from Boise State University in 2008. I
14 began my career at Idaho Power after graduating from the
15. University of Idaho in 1987, and have held several
16 engineering positions before moving into management in
17 2005. In 2005, I was named Vice President of Delivery
18 Engineering and Operations. In 2009, I was appointed to my
• 19 current position as Senior Vice President of Power Supply.
20 My current responsibilities include overseeing the
21 operation and maintenance of Idaho Power's generation
22 fleet, power plant engineering and construction,
23 environmental affairs, water management, power supply
24 planning, and wholesale electricity and gas operations.
25
383
GROW, DI 1
Idaho Power Company
1 Q. What is the purpose of your testimony in this
2. matter?
3 A. The purpose of my testimony is to present the
4 Company's requests to modify the Idaho Public Utilities
5 Commission's ("Commission") implementation of the Public
6 Utility Regulatory Policies Act of 1978 ("PURPA") as it is
7 applied in the state of Idaho and more particularly to
8 Idaho Power. I will provide an overview of the Company's
9 case and summarize the major points contained in the
10 testimony of the Company's witnesses.
11 . I. INTRODUCTXON
12 Q. What has the Commission stated with regard to
S 13 the purpose and/or scope of the present proceeding?
14 A. In its order maintaining the 100 kilpwatt
15 ("kW") published rate eligibility cap for wind and solar
16 Qualified Facilities ("QF"), Case No. GNR-E-11--01, the
17. Commission stated that it was initiating "additional
18 proceedings to allow the parties to investigate and analyze
19 both the SAR Methodology and the IRP Methodology" and that
20 "we [the Commission] encourage a full examination of the
21 application of the IRP Methodology and are open to
22 considering alternatives to the current methodologies."
23 Order No. 32262, pp. 8-9.
24 Additionally, in its Notice of Review for this • 25 matter, Case No. GNR-E-11-03, the Commission further
384
GROW, DI 2
Idaho Power Company
1 directed that this proceeding investigate and review the
2 methodologies for calculating avoided cost rates for Us
3 pursuant to PtJRPA. Order No. 32352. With regard to the
4 investigation and scope of this particular proceeding, the
5 Commission further stated that it, "seeks information
6 regarding the appropriateness of both the SAR and IRP-based
7 avoided cost methodologies. Specifically, the calculation
8 of avoided cost rates, for both published and negotiated
9 contracts, is being re-examined." Id., p. 4.
10 Additionally, "the Commission anticipates that the scope of
11 this inquiry will also include (but is not limited to)
12 considerations regarding the dispatchability of varying
13 resources, curtailment options, integration costs,
14 renewable energy credits, delay security and liquidated
15 damages, timing and schedule of negotiations, and contract
16 milestones." Id.
17 Q. Is this matter also referred to as "Phase III"
18 of the PURPA avoided cost rate proceedings that were
19 initiated in November 2010?
20 A. Yes. This is considered Phase III of those
21 proceedings.
22 Q. Could you summarize Phase I and Phase II of • 23 these proceedings?
24 A. Yes. Phase I began when Idaho Power, Avista, • 25 and Rocky Mountain Power filed a Joint Petition on November
385
GROW, DI 3•
Idaho Power Company
•• 1 5 2010, in Case No. GNR-E-10-04, requesting the Commission
2 initiate an investigation to address various avoided cost
3 issues related to the implementation of PURPA in Idaho.
4 The utilities were experiencing numerous requests for PURPA
5 contracts from large, utility-scale projects that were
6 being disaggregated in order to take advantage of the
7 published rates only available to smaller projects. The
8 utilities requested that the Commission immediately lower
9 the eligibility cap from 10 average megawatts to 100 kW
10 •during the investigation.
11 On December 3, 2010, the Commission declined to
12 lower the eligibility cap immediately and set a schedule to
• 13 process the Joint Petition through Modified Procedure and
14 oral arguments. Order No. 32131. The Commission also
15 directed that if a decision to lower the cap was made, it
16 would be effective as of December 14, 2010.
17 1 In Order No. 32176, issued on February 7, 2011, the
18 Commission granted part of the request by lowering the
19 eligibility cap for wind and solar projects to 100 kW, but
20 the cap for other resource types remained unchanged. The
21 order also directed the parties to meet within 10 days to
22 establish a schedule for Phase II which would address the
23 disaggregation issue.
24 Commission Order No. 32195 established a schedule
• 25 for Phase II, in Case No. GNR-E--11-01, which culminated
386
GROW, DI 4
Idaho Power Company
1 with a Technical Hearing the week of May 9, 2011. The
2 Commission also directed the parties to provide information
3 regarding how small wind and solar QFs could continue to
4 have access to published avoided cost rates without
5 allowing large QFs to obtain a rate that does not
6 accurately reflect a utility's avoided cost. In Order No.
7 32262, issued on June 8, 2011, the Commission determined
8 that the published rate eligibility, cap for wind and solar
9 QFS would remain at 100 kW, and the Commission would
10 undertake, a more detailed examination of the methodologies
11 used to set avoided cost rates. Order No. 32262 also
12 •directed the parties to meet to establish an issues list
13 and a schedule for Phase III, which is this present case,
14 GNR-E-11-03.
15 II. CASE STRUCTURE AND WITNESS SUMMARY
16 Q. Could you please provide an overview of Idaho
17 Power's case and summarize the testimony of the Company's
18 witnesses?
19 A. Yes. The next witness for the Company is M.
20 Mark Stokes, Manager of Power Supply Planning. Mr. Stokes
21 describes the current status of PURPA QF projects on Idaho
22 Power's system, as well as the current implementation of
23 both the Surrogate Avoided Resource-. ("SAR") and Integrated
24 Resource Plan- ("IRP") based avoided cost methodologies in • 25 Idaho. He also addresses issues related to risk and harm
387
GROW, DI 5
Idaho Power Company
S i to Idaho Power customers, contract term, contracting
2 process, and presents the Company's proposal to utilize the
3 IRP-based methodology for establishing the avoided cost for
4 all PURPA QF projects, and for both published and
5 negotiated rates.
6Q. Does the Company present any testimony
7 regarding utility operations?
8 A. Yes. Tessia Park, Load Serving Operations
9 Director, presents testimony regarding utility operations
10 with regard to PURPA QFs and the Company's requirements to
11 reliably serve load. Ms. Park provides testimony regarding
12 the economic dispatch of Idaho Power's resources, and how
13 economic dispatch decisions come in to play when
14 incorporating PURPA QF generation into Idaho Power's
15 system. Ms. Park discusses the requirements of federal
16 regulations, particularly 18 C.F.R. § 292.304, and how they
17 interact with certain light load operational situations on
18 the Company's system. Ms. Park explains and presents the
19 Company's proposed new Tariff Schedule 74 which sets forth
20 an authorized curtailment policy and procedure for PURPA QF
21 generation pursuant to 18 C.F.R. § 292.304(f).
22 Q. Does the Company have any other witnesses?
23 A. Yes. The Company engaged an outside
24 consulting firm, Charles Rivers & Associates, to evaluate
S 25 Idaho Power's system, the current implementation of PURPA
388
GROW, DI 6
Idaho Power Company
• 1 QF requirements in the state of Idaho, the current avoided • 2 cost methodologies employed by the Commission, and other
3. PURPA related issues relevant to this proceeding. Mr.
4 William Hieronymus from Charles Rivers & Associates
5 discusses the history and origins of PtJRPA requirements and
6 the implementation of those requirements in various
7 jurisdictions. Mr. Hieronymus also presents various
8 methods that have been utilized across the country to
9 calculate and establish avoided cost rates and prices
10 pursuant to PURPA. He also discusses issues related to the
11 allocation of risk in PURPA QF transactions such as pricing
12 and contract term. Finally, Mr. Hieronymus discusses the • 13 avoided cost methodology employed in the state of Idaho and
14 discusses Idaho Power's proposed revisions to the
15 methodology presented in this case.
16 Q. Does Idaho Power propose any changes to the
17 avoided cost methodologies?
18 A. The Company's final witness to provide direct
19 testimony is Karl Bokenkamp, Power Supply's Director of
20 Operations Strategy. He provides testimony setting forth
21 the Company's proposed changes, or modifications, that
22 Idaho Power requests for the implementation of the IRP
23 methodology.
24 . .
25
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GROW, DI 7 .
Idaho Power Company
• 1 III. CASE StTh4MRY
2 Q. What are Idaho Power's major concerns in this
3 case?
4 A. Idaho Power is deeply concerned about the
5 negative economic impact caused by the implementation of
6 PURPA and its requirements, as well as the detrimental
7 effect that the accumulated and continuing addition of
8 PURPA QF generation is having on Idaho Power's system and
9 operations. The economic ramifications are extremely
10 harmful to customers. Idaho Power is very concerned that
11 the avoided cost methodologies approved by the Commission
12 have become disconnected from federal requirements and the
13 definition of avoided cost. This has resulted in an
14 environment that has fostered rapid and uncontrolled
15 development of QF generation projects that are causing
16 substantial harm to Idaho Power customers by greatly
17 inflating power supply costs while at the same time
18 degrading the reliability of the system.
19 Idaho Power's main concern is that the Company is
20 obligated to take a very large amount of generation that it
21 does not need and is not valuable to its operations, while
22 at the same time paying more for it than other generation
23 or market purchases that are available to serve load. The
24 Company is also very concerned about the very large and • 25 dramatic increase in power supply costs that must be borne
390
GROW, DI 8
Idaho Power Company
1 by customers because of the mandatory QF purchases that
2 cost more than the Company's own generation or alternative
3 purchases. Idaho Power desires that the requirements of
4 PURPA continue to be met, but also wants to ensure that
5 Idaho Power's requirements of providing safe, reliable, and
6 low cost power to its customers is not undermined in doing
7 so.
8 Q. What does Idaho Power see as problems with the
9 current implementation of PURPA?
10 A. Several things: (1) The continuing and
11 unchecked requirement for the Company to acquire QF
12 generation, pursuant to avoided cost rates, with no regard
13 for the Company's need for additional generation on its
14 system, nor the availability of other lower cost resources,
15 and in a manner inconsistent with the federal definition of
16 avoided cost; (2) Circumvention of the Company's required
17 IRP planning process and a continuing requirement to
18 acquire generation outside of that established process that
19 inflates customers' power supply costs; (3) System
20 reliability and other operational issues caused by a rapid
21 and large scale increase in intermittent and unreliable
22 generation sources; and (4) Most importantly, a dramatic
23 increase in the price that Idaho Power's customers must pay
24 for their-energy needs as a direct result of the large
• 25 quantities of additional QF generation at prices in excess
391
GROW, DI 9
Idaho Power Company
1 of the Company's avoided cost, and beyond that which would
2 otherwise be considered prudent.
3 These items are discussed in more detail in the
4 direct testimony of Mr. Stokes.
5 Q. How does the large increase in PURPA
6 generation affect Idaho Power's customers?
7 A. Customers pay 100 percent of PURPA power
8 supply costs in the annual Power Cost Adjustment ("PCA").
9 These costs, while never insignificant, were relatively
10 small and stable from 1982, when the first QF projects were
11 connected to the Company's system, until about 2003. Since.
12 2004, PURPA expense has grown dramatically, and customers
13 will see very significant annual rate increases out to 2026
14 based upon the current QF projects that are currently
15 generating, and those that have approved power sales
16 agreements to date. As shown in more detail in the
17 testimony of Mr. Stokes, annual PURPA power supply expenses
18 in 2004 were approximately $40 million. It took more than
19 20 years of accumulation of annual PURPA expense to amount
20 to the 2004 one-year magnitude of cost. Just five years
21 later, by 2009, that amount grew by 50 percent to
22 approximately $60 million. Just another three years after
23 that, in 2012, that $60 million will double to $120 million
24 of annual PURPA power supply costs. That number increases • 25 to $167 million by 2014, and by 2026, will be $186 million
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Idaho Power Company
1 annually, an approximate 465 percent increase in costs from
2 2004. This will result in dramatic annual rate increases
3 for all of Idaho Power's customers.
4 Q. Please summarize the Company's requested
5 relief in. this case.
6 A. The Company has conducted a comprehensive
7 examination of the process by which the Commission
8 implements the requirements of PURPA and PURPA's
9 corresponding Federal Energy Regulatory Commission
10 regulations. Idaho Power's testimony summarizes the
11 current procedures and methodologies that are in place, and
12 requests changes in several areas. The Company
13 demonstrates through testimony how its proposed changes
14 both comply with the federal requirements of PURPA, and
15 address severe problems with the current implementation of
16 PURPA. If left unaddressed, the current problems .
17 associated with the implementation of PURPA will continue
18 to unnecessarily inflate the power supply costs of its
19 . customers and to degrade the reliability of Idaho Power's
20. system.
21 To address the current and potential economic harm
22 to'Idaho Power customers as a result of continuing to add
23 large amounts of unneeded generation to its system at a
24 high cost, Idaho Power requests first, that all PURPA QF
25 avoided costs be calculated using an IRP-based avoided cost
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Idaho Power Company
1 methodology. This is a large step in the right direction
2 to more closely estimate Idaho Power's avoided cost - the
3 incremental cost that the utility would incur, either by
4 generating the power itself or purchasing it from another
5 source, but for the purchase from the QF. This is also a
6 step in the right direction to better ensure that Idaho
7 Power customers remain neutral as to whether the power was
8 purchased from a QF or otherwise acquired by the utility,
9 as is required by federal law. It also starts to bring
10 some aspects of utility need into the determination of
11 avoided cost prices.
12 Second, the Company requests approval and
' 13 implementation of a standard contracting and negotiation
14 process by which PURPA QFs can obtain a Power Purchase
15 Agreement ("EPA") with Idaho Power in a completely
16 transparent process that provides certainty to both
17 parties, better defines the parties' obligations, and
18 addresses issues frequently brought before the Commission
19 in the form of "grandfathering" requests.
20 Third, to mitigate and reduce the risk born entirely
21 by Idaho Power customers associated with long-term power
22 purchase commitments at a fixed price or rate, Idaho Power
23 requests a reduction in the maximum authorized PPA contract
24 term from its present term of 20 years to a maximum .of five
• 25 years.
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Idaho Power Company
1 To ensure that customers are not harmed by the
2 purchase of power from the QF, and that the Company's lower
3 cost base load resources are being optimized and used to
4 cost-effectively serve customers when available, the
5 Company requests approval of a new Tariff Schedule 74.
6 This Tariff Schedule sets forth the authorized, curtailment
7 policy and procedure for PURPA QF generation pursuant to 18.
8 C.F.R. § 292.304(f).
9 Lastly, the' Company seeks certain modifications to
10 the currently approved IRP-based avoided cost pricing
11 methodology in order to better estimate Idaho Power's
12 avoided cost, and to align the methodology with the . 13 definition of avoided cost from federal law. This request
14 is essentially a modification to the present implementation'
15 of the IRP-based methodology that better aligns the
16 methodology with the definition of avoided cost from
17 federal regulations.
18 Q. You stated earlier that the Commission
19 mentioned renewable energy credits ("RECs") in a list of
20 possible issues in Order No. 32352. Does the Company have
21 a proposal as part of this case regarding RECs?
22 A. Issues related to PURPA QFs and RECs are
23 currently being litigated by the Company before the
24 Commission in Case No. IPC-E-11-15. The Commission has had • 25 proceedings in the past regarding issues related to the
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Idaho Power Company
1 'ownership of RECs between PURPA QFs and the purchasing
2 utility, but the: issue of ownership of RECs in the state of
3 Idaho remains an unsettled issue. Idaho Power understands
4 that the Idaho Legislature, which is currently in session,
5 may be considering proposed legislation that would address
6 the ownership of RECs from PURPA QF projects, and thus the
7 Company has no specific request of the Commission in this
8 regard at this time.
9 Q. Please detail the specific approval the
10 Company is requesting from the Commission.
11 A. The Company requests specific Commission
12 approval of the following:
13 1. The use of an IRP-based methodology for
14 establishing avoided cost rates for all PURPA QF projects;
15 2. Establishment of a Commission-
16 authorized negotiation process and procedure by which a
17 PURPA QF can obtain a PPA with Idaho Power;
18 3. A reduction in the maximum term for
19 PURPA QF PPAs from 20 years to five years;
20 4. The Company's proposed Tariff Schedule
21 74 setting forth the Company's authorized curtailment
22 policy and procedure for PURPA QF generation pursuant to 18
23 C.F.R. § 292.304(f); and
24 5. The Company's proposed modifications to • 25 the previously approved IRP-based avoided cost methodology.
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Idaho Power Company
1 The Company believes that these determinations can
2 reasonably be made based upon the full and detailed
3 testimony provided by the Company in this case,
4 Q. Is it your opinion that the granting of the
5 requested relief proposed by the Company is in the public
6 interest?
7 A. Yes. The great advantages that Idaho Power
8 customers, its service territory, and its region enjoy from
9' consistently having among the very lowest electricity
10 prices in the nation are being eroded by a flood of QF
11 generation that we all are paying too much for. Idaho
12 Power is forced to purchase this power with no regard to
01
13 whether it is needed on its system, with no regard to
14 whether it is called for in the Company's IRP process, and.
15 with no regard to whether there are other lower cost
16 alternatives for its customers. Additionally, the Company
17 is forced to deal with the difficult tasks and problems
18 associated with integrating large amounts of intermittent
19 and variable renewable generation into its system, once
20 again with customers paying the resulting price. In most
21 instances, customers do not even get the "benefits" derived
22 from the renewable attributes of that generation in the
23 form of RECs, nor is the Company even able to "claim" or
24 get credit for the existence of that renewable energy on
• 25 its system.
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Idaho Power Company
1 In this proceeding we have the unique opportunity to
2 re-examine the appropriateness of the methodologies used to
3 set avoided cost, and to re-examine the way that the state
4 of Idaho implements the federal requirements of PURPA.
5 Idaho Power is deeply affected by these determinations, as
6 are its customers, and has proposed reasoned and rational
7 solutions to both ensure that the requirements of PURPA
8 continue to be met, but also that Idaho Power's
9 requirements of providing safe, reliable, and low cost
10 power to its customers is not undermined in doing so. The
11 Company's proposals are in the public interest, comply. with
12 federal requirements, and the Company respectfully asks the
13 Commission to implement the same.
/
14 Q. Does that conclude your testimony?
15 A. . Yes, it does.
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Idaho Power Company
•: open hearing.)
(The following proceedings were had in
MR. WALKER: And the witness is available for
cross-examination.
COMMISSIONER SMITH: Thank you.
Mr. Solander, do you have questions?
MR. SOLANDER: No questions, thank you.
COMMISSIONER SMITH: Questions?
MR. ANDREA: No questions.
COMMISSIONER SMITH: Mr. Arkoosh, any questions?
MR. ARKOOSH: No questions, thank you.
MR. R. WILLIAMS: No questions. Thank you.
MR. MILLER: No questions.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Thank you, Madam. I do have
some questions.
CROSS-EXAMINATION
BY MR. RICHARDSON:
Q. Good afternoon, Ms. Grow.
A. Good afternoon.
Q. Ms. Grow, is it true that Idaho Power has
embarked on a very sophisticated public relations campaign in
relation to issues we are addressing in these proceedings?
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HEDRICK COURT REPORTING GROW (X)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
1 A. I don't know that I would characterize it as
2 "sophisticated." We had launched an educational campaign to
3 bring awareness to the issues that were impacting our
4 customers, and we believe they should have a voice in it and
5 know what was occurring.
6 MR. RICHARDSON: Madam Chair, may I approach the
7 witness?
8 COMMISSIONER SMITH: You may.
9 MR. RICHARDSON: Thank you, Madam Chair. Or, may
10 we approach the witness.
11 Madam Chair, I am handing out a copy of a flier
12 that accompanied my most recent Idaho Power bill.
S 13 Q. BY MR. RICHARDSON: Ms. Grow, do you recognize
14 this document?
15 A. I don't have it yet.
16 Q. You haven't seen it yet.
17 A. Ida.
18 MR. RICHARDSON: Madam Chair, I'll ask that this
19 document be marked as Exhibit No. 512.
20 (Clearwater Paper Corporation, et al,
21 Exhibit No. 512 was marked for identification.)
22 Q. BY MR. RICHARDSON: Toward the bottom of the
23 first page --
24 And you were the author of this document.
.
25 Correct?
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HEDRICK COURT REPORTING GROW (X)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
A. Correct.
Q. Toward the bottom of the first page, you state
that, quote: Federal law requires Idaho Power to buy
electricity from independent producers, regardless of whether
our customers need it or not.
Do you see that?
A. Yes.
Q. And you continue by stating: To make matters
worse, prices for this energy are set far higher than the price
of electricity readily available on the open market.
Do you see that?
A. Ido.
Q. Correct me if I'm wrong, but when you say "prices
for this energy are set far higher," you are talking about the
avoided cost rate that this Commission sets?
A. That's correct.
Q. And do you know how the avoided cost rate is
set?
A. Ido.
Q. Then you already know then, don't you, that
today's spot market for electricity is not what long-term
avoided cost rates are attempting to reflect, are they?
A. Well, avoided rates are set at what we would
otherwise buy from other resources or generate on our own.
Q. So wouldn't you agree that a comparison of
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HEDRICK COURT REPORTING GROW (X)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
long-term avoided cost rates is an unfair comparison to today's
spot market?
A. I would agree with the spot market comment.
Q. Pardon me?
A. I said I would agree with your spot market
comment. However, again, those are resources that we could
procure today and it is -- they are, in fact, lower than what
we pay for the PURPA resource. But as to how it is -- how it
is relevant to the avoided rate, I agree.
Q. That it's misleading?
A. I don't think it's misleading. I think it's
absolutely factual that the prices are set higher than the spot
market. That is factual; that's a simple math problem.
Q. And the comparison of long-term avoided cost
rates, they're not -- long-term avoided cost rates are not
designed to identify what today's spot market is, are they?
A. Correct.
Q. And when you say, "To make matters" -- quote: To
make matters worse, prices for this energy -- and when you say
"this energy," you said earlier that you were referring to the
avoided cost rates set by this Commission -- for this energy
are set far higher than the price of electricity readily
available -- which I assume you mean the spot market?
A. That, among other things, sure.
Q. And you don't think that's misleading?
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HEDRICK COURT REPORTING GROW (X)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
A. I don't.
Q. Now, Ms. Grow, I've been asked this question a
lot of times since your PR campaign began and I think I have
responded properly to the various people who asked, and so in
order to give the ratepayers and folks who are concerned about
this a chance to have their concern alleviated, I'll ask you
the question that I've been asked a lot:
It's not the Company's intent, is it, to charge
the ratepayers for any of your public relation activities in
regard to attacking wind?
A. We are not attacking wind.
Q. And this sophisticated PR campaign we talked
about earlier, do you plan to charge the ratepayers for those
activities?
A. None of our commercial or PR activities are ever
charged to the customer.
Q. In the flier, you express concern on behalf of
Idaho Power's customers because of the amount of money the
Company will be paying for what you term alternative energy.
Correct?
A. Correct.
Q. Well, this isn't just about Idaho Power's
customers, is it?
A. It absolutely is.
Q. Wouldn't you agree that Idaho Power's owners, the
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HEDRICK COURT REPORTING GROW (X)
P. 0. BOX 578, BOISE, ID 83701
Idaho Power
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A. Absolutely not. Absolutely not. They are
indifferent.
Q. Well, you're one of those shareholders, aren't
you?
A. I am.
Q. And so you have a stake in this, don't you,
personally?
A. Again, this doesn't have anything to do with the
shareholders. One hundred percent of the costs of PURPA get
passed on to the customer, so it has no impact to our bottom
line.
Q. Now, you mentioned the planning process for the
IRP in this flier, and you observe that the requirement to buy
energy from these producers at inflated rates, at inflated
prices, circumvents this public planning process. Do you
recall that?
A. Ido.
Q. Now, you also address the IRP process in a couple
of places in your testimony. Specifically on page 9, you state
that one of the problems with PURPA implementation in Idaho is
that, quote, Circumvention of the Company's required IRP
planning process and a continuing requirement to acquire
generation outside of that established process.
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HEDRICK COURT REPORTING GROW (X)
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Do you see that?
A. Ido.
Q. Then over on page 15 of your testimony, you
testify that Idaho Power is forced to purchase power with no
regard to whether it is called for in the Company's IRP
process. Do you see that?
A. Ido.
Q. Now, one of the Company's proposed changes as to
how the Commission sets avoided cost rates is to use the IRP
process going forward. Correct?
A. The IRP methodology.
Q. And is the IRP methodology related in any way to
the IRP process?
A. It is.
Q. And you're planning to use the IRP methodology
going forward. Correct?
A. Going forward with what?
Q. If the IRP methodology is used rather than the
SAR methodology for setting avoided cost rates, would you agree
that the IRP process will have more significance to potential
QF developers going forward?
A. More significance in what way?
Q. In terms of instructing the IRP methodology for
how avoided cost rates are set. Don't you think a developer
would be more interested in the IRP process if the Commission
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HEDRICK COURT REPORTING GROW (X)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
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3 A. I don't have an opinion about what developers
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Q. The IRP process includes members of the public
and stakeholders. Correct?
A. Correct.
Q. And who is on the IRP team?
A. I don't know all the names. Mark Stokes would be
a better witness to ask that question.
MR. RICHARDSON: May we approach the witness?
COMMISSIONER SMITH: You may.
MR. RICHARDSON: Madam Chair, we're handing out
Idaho Power's Response to Exergy's Request for Production
No. 65 to Idaho Power.
COMMISSIONER SMITH: Mark this as 513.
MR. RICHARDSON: Would like it marked as
Exhibit 513, please.
19 COMMISSIONER SMITH: Yes, sir.
20 (Clearwater Paper Corporation, et al,
21 Exhibit No. 513 was marked for identification.)
22 Q. BY MR. RICHARDSON: Is this an accurate
23 representation of the membership of the IRP advisory council?
24 A. As it was constructed for the 2011 IRP advisory
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25 committee, yes.
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P. 0. BOX 578, BOISE, ID 83701 Idaho Power
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Q. I'm sorry?
A. As it was constructed, as the membership was, for
the 2011 IRP council.
Q. How are the representatives on the IRP selected?
A. We look at a wide range of issues. We want to
make sure we have a good demographic of stakeholders and
opinions and our customers.
Q. Do you have any written guidelines as to how they
are selected?
A. To my knowledge, no.
Q. Well, could I rely on the language from the IRP
as a guideline where your IRP, your 2011 IRP, says that, quote:
Members of the council include political, environmental, and
customer representatives, as well as representatives of other
public interest groups?
Would that be a fair --
A. Sure.
Q. It's in your 2000 (sic) IRP at page 2. And that
at least gives us a hint of who you will select to be on the
IRP. Correct?
A. Correct.
Q. Do members of the IRP team have a staff that they
can rely on as they evaluate the results of your IRP?
A. I'm not sure I understand your question. Do they
have staff? I don't know.
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HEDRICK COURT REPORTING GROW (X)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
Q. Does Idaho Power provide them with a staff to
help them evaluate your IRP?
A. Do Idaho Power employees guide the process or
help with the process? Yes.
Q. Do the members of the team have professional
help, assistance, experts that Idaho Power provides them with
to evaluate the IRP?
MR. WALKER: Objection: That's been asked and
answered.
COMMISSIONER SMITH: Well, I'm going to overrule
the objection, because I don't know that I -- I don't know I
have a grasp on the question, let alone the answer. So maybe
try again, Mr. Richardson.
MR. RICHARDSON: Would you like me to rephrase
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16 COMMISSIONER SMITH: Sure.
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Q. BY MR. RICHARDSON: Does Idaho Power provide an
18 independent staff group to members of the IRP team?
19 A. What do you mean by "independent"?
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Q. That do not report to Idaho Power?
21 A. I don't know the answer to that. I'm not sure
22 what you're referring to.
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Q. Now, the folks who make presentations at the IRP
24 meetings are either employees of the Company or consultants to
25 the Company. Correct?
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1 A. Again, these would be better questions for
2 Mark Stokes, who runs that process.
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Q. Do you attend the IRP meetings?
A. From time to time, but I'm not at every one of
them.
Q. I didn't ask you about every one. The ones you
have attended, Ms. Grow, have the presenters all been employees
of Idaho Power or consultants to the Power Company?
A. I -- I would -- I honestly can't remember every
meeting, so I would say predominantly so. But if there was an
occasional one, I don't know.
Q. Now, the Company writes the IRP. Correct?
A. That's correct.
Q. And it's a Company document?
A. Correct, which is our obligation to provide to
the PUC.
Q. Would you say that the limited time you've been
to an IRP meeting, would you say that the presentations you've
seen are subjected to rigorous examination and scrutiny by the
members of the team?
A. I have not witnessed that. I presume they are
very engaged, they are asking questions, they are -- they are a
good place to vet the issues at hand.
Q. Would you say that the Company's presentations at
the IRP meetings are subjected to rigorous examination and
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HEDRICK COURT REPORTING GROW (X)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
scrutiny by members of the team with equivalent education and
experience as the Idaho Power presenters?
A. I have no way of knowing that.
Q. At the end of the day, aren't all final decisions
as to what is either in or out of the IRP is solely in the
hands of the Company?
A. Well, the obligation to serve is solely in the
hands of the Company.
Q. And in your IRP at page 2, it provides that --
your 2011 IRP, pages 2 to 3 -- quote: Idaho Power and the
members of the IRPAC recognize that outside perspective is
valuable, but also recognize that final decisions on the IRP
are made by Idaho Power.
Does that ring a bell with you?
A. Sure.
Q. So at the end of the day, the IRP says what Idaho
Power wants it to say, even if the IRP members disagree?
A. I would disagree with that statement. We let
others disagree. In fact, we think the process is better
informed with that.
Q. But you agreed with the characterization -- well,
the provision that I just read to you, that final decisions on
the IRP are made by Idaho Power?
A. To the extent that we ultimately, not the IRPAC,
which is an advisory committee. They don't have an obligation
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to serve. They aren't the ones that go out and have to make
sure that the supply is adequate for our customers now and in
the future at a reasonable cost and avoiding as much risk as we
can. They don't have that same obligation we do.
Q. So I'll get back to the question:
So at the end of the day, the IRP says what Idaho
Power wants it to say, even if IRP members disagree with the
conclusion. Correct?
A. I would -- I would say so.
Q. So what happens to IRP members who fall out of
favor with the Power Company? Do you kick them off?
A. No.
Q. The IRP at page 2 says, quote: The IRP is better
because of the public involvement.
Yet isn't it really saying that the IRP is better
because of public involvement from only members of the public
that agree with Idaho Power?
A. Absolutely not.
Q. Have you ever read any of the Commission's Orders
in response to Idaho Power's IRP filings?
A. There are no Orders. They acknowledge.
Q. Pardon me?
A. They acknowledge the IRP.
Q. I'll read from your most recent IRP Order that
the Commission read:
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HEDRICK COURT REPORTING GROW (X)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
Based on our review, we find it reasonable to
accept for filing and to acknowledge Idaho Power's 2011
electric integrated resource plan. Our acceptance of the 2011
IRP should not be interpreted as an endorsement of any
particular element of the plan, nor does it constitute approval
of any resource acquisition contained in the plan.
Does that sound familiar?
A. Yes, it does.
Q. Now, suppose the Commission used that language
when you filed for your certificate of convenience and
necessity to build Langley Gulch. Do you think you could take
that to the bank and finance that project with it?
A. We've done that for years.
Q. What did the Order for approval of Langley Gulch
say?
A. Well, in that case, it came with --
Q. I was asking you about Langley Gulch.
A. Well, we would go to Wall Street and we would
raise the money, like we have for every other one. In this
case, we had preapproval.
Q. Which meant what?
A. Which meant a certain portion of the capital
costs were sort of -- we -- preapproved. So we went through
the need and all of the stuff that we would have gone through
with a rate case in advance of the resource.
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HEDRICK COURT REPORTING GROW (X)
P. 0. BOX 578, BOISE, ID 83701 Idaho Power
Q. So that Order on Langley Gulch tied this
Commission's hands from doing a prudency review, didn't it?
3 A. No, absolutely not. That was the prudency
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Q. From doing a prudency review when the plant came
6 online?
7 A. They did the prudency review in advance of the
8 plant coming online.
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Q. And that tied this Commission's hands from doing
10 a prudency review in June of this year when the plant came
Now online?
A. It was already done.
Q. Yep, it was a done deal.
A. The prudency was already done.
MR. WALKER: Objection, your Honor, or Madam
Chair: This is getting argumentative.
COMMISSIONER SMITH: I agree, it's very
argumentative.
Q. BY MR. RICHARDSON: So, well, let's just
summarize and move on. The Commission doesn't approve the IRP.
Correct?
A. They acknowledge it.
Q. And Idaho Power gets to decide what's in the IRP.
Correct?
A. We work with a committee to decide what's in it.
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Q. And Idaho Power gets to decide who has a seat at
the table when you draft the IRP. Correct?
A. We look for a cross section of people to be on
that committee, yes.
Q. And the IRP team members are not provided with
independent experts to scrutinize its details. Correct?
A. I still don't know what you mean.
Q. So, with all of that in mind, Ms. Grow, would you
have to agree that the development community's skepticism of
the IRP for setting avoided cost rates is well placed?
A. No, I don't agree with that.
Q. In your capacity as senior vice president of
power supply, is one of your responsibilities to review and
sign power purchase agreements with PURPA projects on behalf of
Idaho Power?
A. It is.
Q. And at the time you sign the power purchase
agreement, are you familiar with its terms and conditions?
A. I am.
Q. And does your signature constitute an acceptance
of the terms of the power purchase agreement by Idaho Power?
A. It does.
Q. And does your signature constitute Idaho Power's
commitment to perform according to the terms of the power
purchase agreement?
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1 A. It does.
2 MR. RICHARDSON: Madam Chair, may I approach the
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COMMISSIONER SMITH: Yes, you may.
Q. BY MR. RICHARDSON: Ms. Grow, do you recognize
this?
COMMISSIONER SMITH: Shall we mark it as
Exhibit 514?
MR. RICHARDSON: Thank you, Madam Chair.
(Clearwater Paper Corporation, et al,
Exhibit No. 514 was marked for identification.)
THE WITNESS: I'm not sure I do or don't. I
don't have any context for this. I don't know what this is.
Q. BY MR. RICHARDSON: Would you accept this is an
excerpt from one of your most recent draft power purchase
agreements that would -- does it not look familiar to you?
A. It looks similar, but I can't say whether it is
or isn't.
Q. Okay. Well, look at Article 29, and would you
read that into the record?
A. "This agreement constitutes the entire agreement
of the parties concerning the subject matter hereof and
supercedes all prior or contemporaneous oral or written
agreements between the parties concerning the subject matter
hereof."
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MR. WALKER: Madam Chair, I'm going to object at
this time: There's been no foundation laid to determine where
the language on this page came from, what its origin is,
whether or not it's part of an actual PURPA agreement or not,
and I would object to its admission as an exhibit and its use
in this line of questioning.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Madam Chair, I was just going to
ask the foundational question.
COMMISSIONER SMITH: All right.
Q. BY MR. RICHARDSON: You recognize this language
as language that's typically inserted in all of your power
purchase agreements with QFs, don't you?
A. I suppose so. Again, I would need more
background.
Q. And this is commonly called an "entire agreement
clause." Correct?
A. I'm not a lawyer.
MR. WALKER: Madam Chair, I renew my objection:
There's still no foundation to show that this is part of any
actual agreement; and what the point is beyond that, I don't
know.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Madam Chair, I use the excerpts
hopefully in terms of efficiency. I can certainly get a full
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standard agreement and introduce it into the record if Counsel
won't accept that this is the standard power purchase agreement
language from Idaho Power's QF agreements.
COMMISSIONER SMITH: Don't we have some
agreements in the exhibits somewhere?
COMMISSIONER KJELLANDER: Yes, we do.
MR. MILLER: Madam Chairman.
COMMISSIONER SMITH: Mr. Miller.
MR. MILLER: I might be able to be helpful.
COMMISSIONER SMITH: Excellent.
MR. MILLER: A rare event. Exhibit 2201 --
COMMISSIONER SMITH: Okay. Thank you. I knew
there were exhibits.
MR. MILLER: -- is a fully-executed power
purchase agreement --
MR. RICHARDSON: Thank you.
MR. MILLER: -- with I think a clause identical
to the recently-distributed exhibit.
COMMISSIONER SMITH: So what witness was that?
Oh, it's not a witness.
How about Exhibit 2106. That looks like a power
purchase agreement.
MR. RICHARDSON: Madam Chair, there's two places
where there's full power purchase agreements that appear in the
record. One is Exhibit 2201, entitled Firm --
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COMMISSIONER SMITH: Well, 2201 isn't here yet,
so let's find another one.
MR. RICHARDSON: 2110.
COMMISSIONER SMITH: Okay.
MR. WALKER: May I ask whose -- whose exhibit
that is, who's that attached to?
COMMISSIONER SMITH: Mr. Miller.
So, we're going to look at Exhibit 2110.
MR. RICHARDSON: Correct. It's a proffered
exhibit by Mr. Guy of Idaho Wind Partners I, LLC.
COMMISSIONER SMITH: We've got it. Do you have a
copy for the witness?
THE WITNESS: Yeah, I don't have it.
MR. WALKER: I still don't know what exhibit and
what contract we're talking about, and maybe Mr. Richardson has
a copy for her if he wants to ask a question about it.
MR. RICHARDSON: Madam Chair, could Counsel for
the witness make Exhibit 2110 available.
COMMISSIONER SMITH: Commissioner Kjellander will
do that.
COMMISSIONER KJELLANDER: (Indicating.)
COMMISSIONER SMITH: Exhibit 2110 was attached to
the prefiled testimony of Mr. Guy.
MR. WALKER: And, Madam Chair, would that be the
firm energy sales agreement between Idaho Power Company and
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Camp Reed Wind Park, LLC?
COMMISSIONER SMITH: That's what it appears to
be, and it's a 2009 Agreement.
Q. BY MR. RICHARDSON: Ms. Grow, you recognize this
as a power purchase agreement executed by your predecessor in
your job as senior vice president of power supply?
A. I don't have a signature page, so, no.
COMMISSIONER SMITH: You didn't give her the
whole thing?
COMMISSIONER KJELLANDER: (Indicating.)
THE WITNESS: He was a representative of power
supply. He was not my predecessor.
Q. BY MR. RICHARDSON: Looking at Exhibit 2110 --
you just read what I handed out as Exhibit 514?
A. Hold on. This is shown as Exhibit 2102. Are we
on the same sheet? What did you say? You said 2100?
Q. 2110.
A. 2110. I have 2102.
COMMISSIONER SMITH: It's further back. 2110.
COMMISSIONER KJELLANDER: They were combined
together, those two pages.
(Discussion off the record.)
COMMISSIONER SMITH: Do you have it?
COMMISSIONER KJELLANDER: No, this is the only
other thing I have.
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Mr. Richardson, if you use 2102, would that give
you everything you need?
MR. RICHARDSON: Pardon me?
COMMISSIONER KJELLANDER: The language is the
same in 2102.
MR. RICHARDSON: I don't have 2102.
COMMISSIONER KJELLANDER: There you go.
MR. RICHARDSON: I just was made available 2102,
so I can use that one.
COMMISSIONER KJELLANDER: (Indicating.)
THE WITNESS: Okay. Okay, so --
Q. BY MR. RICHARDSON: Are we on the same page?
A. I don't know. What page are you on?
Q. I think I want 2102.
A. Okay, I have 2102 before me.
Q. Wonderful. So if you would turn to Article 29 of
Exhibit 2102 --
First of all, do you recognize this as a typical
Idaho Power firm energy sales agreement for a QF?
A. It looks typical.
Q. Pardon me?
A. It looks typical, yes.
Q. Would you read Article 29 into the record for us,
please?
There's not a 29 in this one. It would be
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Article 32.
A. Okay: This agreement constitutes the entire
agreement of the parties concerning the subject matter hereof
and supercedes all prior or contemporaneous oral or written
agreements between the parties concerning the subject matter
hereof.
Q. Thank you.
MR. RICHARDSON: And I'd note, for the record,
that that language is identical to the language Ms. Grow read
from Exhibit 514.
Q. BY MR. RICHARDSON: And does this clause protect
Idaho Power against the possibility that a counterparty -- that
the counterparty will subsequently claim that there was some
sort of oral side deal?
A. I am not a lawyer.
Q. You don't have any idea what this clause means?
A. Well, I won't opine about what somebody will use
it for or what it protects against. I will defer to my lawyer.
Q. Actually, I would like you to take --
Okay, I'm going to move on to a different
subject.
A. Okay.
Q. Have you read the Staff's testimony in this case?
A. At a high level.
Q. Pardon me?
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A. At a high level, I have.
Q. You have read it?
A. Yes. I wouldn't say I have it committed to
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memory.
Q. That's not what I asked.
A. Okay.
Q. I just said, Have you read it?
A. I have read it.
Q. Would you please refer to Staff witness
Sterling's direct testimony at page 44.
A. I don't have his testimony with me.
Q. Well, I can read it to you if you like and you
can -- you said you hadn't committed it to memory. Maybe you
better take a look at it.
COMMISSIONER SMITH: Well, do you want to provide
her with it, Mr. Richardson.
MR. RICHARDSON: Sure.
COMMISSIONER KJELLANDER: I've got it.
THE WITNESS: Do you want to switch chairs?
COMMISSIONER KJELLANDER: Might be easier.
Mr. Richardson, the witness has it before her.
COMMISSIONER REDFORD: What page is that,
Mr. Richardson?
Q. BY MR. RICHARDSON: Page 44, beginning on line
16, where Mr. Sterling states: Thus, FERC concluded that RECs
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1 are created by the state and controlled by state law, not
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PURPA, and that they may be decoupled from renewable energy.
3 More specifically, FERC ruled that the states have the power to
4 determine who owns RECs.
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Do you agree with Mr. Sterling?
A. On that, I do.
Q. Can you point me to the Idaho law that creates
RECs?
A. There is not a -- currently a state law that
creates RECs, but they are, as one of the previous witnesses,
those are created and can be sold into other markets and so it
isn't necessarily only a function of Idaho state law that
creates them.
Q. So in other words, you cannot point me to an
Idaho law that creates RECs?
A. Correct.
Q. Now, I have prepared an exhibit to show a very
simple proposition and it's -- unfortunately, it's based on a
confidential information that Idaho Power provided to us in a
Discovery Request, but the very simple -- and I don't want to
disrupt the hearing room by deciding who here has and hasn't
signed a confidentiality agreement. Maybe if you agree with me
on this, I can move on without bothering to do that.
So I'll simply ask you do you agree with me that
RECs are valuable?
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1 A. Not always.
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Q. They have value?
3 A. Sometimes.
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Q. And Idaho Power sells them?
5 A. We do.
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Q. And you -- what was your most recent report to
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that.
A. I don't have that number with me.
Q. Millions of dollars, wouldn't you agree?
A. Uh-huh.
Q. Are they property?
A. I am not a lawyer. I don't know how to
Q. So when you sell a REC, how do you prove you own
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it?
A. It's registered. We do own it.
Q. It's registered. Has a title?
A. Well, we put it through the WREGIS system or it's
a contract that says it's ours.
Q. I'm sorry?
A. Or it's a contract, in the contract it is stated
that they are ours.
Q. Do you believe that Idaho Power, as a Utility
purchasing PURPA QF electricity, is the rightful owner of RECs?
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r 1 A. I believe our customers are.
2 Q. How do they take title to the RECs?
3 A. That's what part of this proceeding is about.
4 Q. You believe your customers currently own the
RECs?
A. No, I think it's undecided, should they.
Q. It's undecided or --
A. I believe that they are entitled to them, but it
is undecided as a matter of policy.
Q. Do you recall that the Idaho Commission has
routinely approved PURPA QF contracts that contain -- that
contained a clause where Idaho Power explicitly disclaimed
ownership of RECs?
A. We did.
Q. And do you recall that the Commission Staff
routinely recommended the Commission approve those contracts
that contained language explicitly disclaiming REC ownership?
A. They did.
Q. Now, Idaho Power stopped inserting the language
explicitly disclaiming ownership of REC5 on your watch as VP of
power supply. Is that correct?
A. That's correct.
Q. And do you know when the last contract was
executed to explicitly disclaim REC ownership?
A. I don't.
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Q. Well, I would suggest that you signed that
contract on January 28 of 2011 for Western Desert Energy. Does
that ring a bell?
A. I -- I don't know.
Q. In Idaho Power Case E-11-01.
Then after January of 2011, and also on your
watch as VP of power supply, Idaho Power began attempting to
insert the clause -- a clause in the contracts asserting that
REC ownership will be determined by applicable federal or state
law. Do you recall that?
A. I correct it. I'm not sure of the dates, but the
language is correct.
Q. And you tried to insert the what I'll call the
applicable law clause in the very next contract you signed with
a PURPA developer, didn't you?
A. I'm not sure what your question is.
Q. Well, it looks like for the very next contract
after the Western Desert contract, which was January of 2011,
you entered into an agreement with the Clark Canyon Hydro where
you tried to put that language in the contract. Do you recall
that?
A. Not specifically. I don't negotiate the
contracts.
Q. I'm sorry?
A. I don't personally negotiate the contracts, so if
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it's that specific one, I will, subject to checking it.
Q. And you sign them though?
A. Ido.
Q. And you read them?
A. Ido.
Q. Not at a high level though?
A. You were saying that I attempted to insert them,
and I'm telling you I didn't. I personally did not.
Q. I'd say Idaho Power attempted to insert them?
MR. WALKER: Madam Chair, excuse me. I have an
objection to the relevance of this line of questioning. It's
getting very argumentative and repetitive, and I'm not sure if
there's been any demonstration of the relevance to avoided
costs.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: It's relevant to the Company's
position on REC ownership, the policy question of REC
ownership, and the legal question of REC ownership. Obviously,
I'm not asking the witness any legal conclusions, but I'm
trying to establish how the Company has treated RECs in the
past, if they changed their position of how they treat REC5
now, and trying to establish the reasons for that.
COMMISSIONER SMITH: Well, maybe there's a more
direct way than confusing the witness in the time sequence.
Q. BY MR. RICHARDSON: Well, I'll represent to you,
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Ms. Grow, that the Western Desert Energy contract signed in
January of 2011 expressly disclaimed REC ownership. That was
approved by this Commission in Idaho Power Case Docket E-11-01.
And then the next power purchase agreement
approved by this Commission was Clark Canyon hydro. And you
recall that contract. Correct?
A. It's one of 119.
Q. Pardon me?
A. It's one of 119 contracts we have.
Q. You don't recall it?
A. Not specifically.
Q. Well, Clark Can-
MR. RICHARDSON: May I approach -- may we
approach the witness, Madam Chair.
COMMISSIONER SMITH: You may.
Actually, let's label this 514 since I'm not
going to admit the previous one page of 514 since we actually
went to a real contract.
MR. RICHARDSON: Thank you, Madam Chair.
(Whereupon, the exhibit previously marked
as Clearwater Paper Corporation, et al, Exhibit No. 514, was
withdrawn, and a new document was marked for identification as
Clearwater Paper Corporation, et al, Exhibit No. 514.)
Q. BY MR. RICHARDSON: Before I start asking a
question on 514, Madam Chair, Ms. Grow, we've -- I think we've
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established that sometime after the Western Desert Energy
contract was signed, that Idaho Power stopped disclaiming
ownership of RECs in firm energy sales agreements?
A. There was some point that we did, correct.
Q. Right. And who made that decision?
A. It was a -- it was a decision that we, as an
executive group, took a look at how many renewable contracts we
were entering into. And at the time, we were concerned about
federal legislation -- and we still are -- which we believe the
customer was paying for renewables and not getting the
attribute, and, in fact, if there was an RPS mandated by either
the state or federal government, we would actually have to go
out and buy more, and the economic harm that was being done to
our customers and the reliability problems that have occurred
as a result made us very concerned. And we felt that that was
an attribute that rightfully belonged to the customers, and
that if something in the future changes, we didn't want the
customers to have to go out and resecure what they already are
entitled to.
Q. So the question was who made the decision?
A. I would say Idaho Power did, and I am part of
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that.
Q. Who at Idaho Power made the decision to stop
disclaiming ownership?
MR. WALKER: Objection: That's been asked and
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answered.
MR. RICHARDSON: It hasn't been answered, Madam
3 Chairman.
4 COMMISSIONER SMITH: Yes, her exact words were
Q. BY MR. RICHARDSON: Who's on the management team
you referred to?
A. I am, the COO, the president, our chief counsel.
Q. I'm sorry, you went a little fast. Could you
repeat that?
A. Our chief operating officer, the president of the
Company, the CEO of the Company, the general counsel.
And it's a responsible -- we talk about all kinds
of strategic things and worries that we have about how it's
impacting our customers. They're very involved.
Q. And this is -- all four of these individuals
regularly get together and have meetings to discuss things like
this?
A. Yes.
Q. Is there an agenda from that meeting?
A. No.
MR. WALKER: Objection, Madam Chair: What's the
relevance of that?
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: The source of the Company's
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policy on REC ownership is one of the major issues in this
case.
THE WITNESS: We talk about lots of things.
MR. WALKER: Excuse me. I don't think the source
is a relevant issue in the case, Madam Chair.
MR. RICHARDSON: The source goes to the
reasonableness. Where did it come from? Why was it developed?
COMMISSIONER SMITH: Well, Mr. Richardson, it's a
corporation that has a management team, and that's the source.
So I think, personally, you've got your answer and -- to that
question.
Q. BY MR. RICHARDSON: Would you take a look at
Exhibit 514?
A. Which one is 514?
MS. SASSER: The most recent one.
THE WITNESS: Is that the one we're not including
anymore?
COMMISSIONER KJELLANDER: No.
THE WITNESS: Oh, that's the one we are.
Q. BY MR. RICHARDSON: It's entitled Agreement for
Transfer of Ownership of Environmental Attributes.
A. I'm sorry. Okay.
Q. Do you have that in front of you?
A. Ida.
Q. And do you recognize that document?
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A. I suppose so.
Q. I'm sorry?
A. I suppose so. Again, there's a lot of things
that go across my desk. I don't have --
Q. Is that your signature on the document?
A. It is.
Q. Can we assume that you signed this document?
A. That's not what you asked me. Yes, I did sign
this.
Q. And do you recognize it now that you see that
your signature is on it?
A. Well, again, I recognize my signature. Do you
have a question about this?
Q. I asked you if you recognize it. Yes, I do have
a question: Do you recognize it?
A. I see it, yes.
Q. Pardon me?
A. I recognize it.
Q. What does this document purport to do?
A. It appears that we entered into a separate
agreement for the environmental attributes of a small hydro.
Q. Please read Paragraph 2 on page 3 into the
record.
A. I'm sorry, Paragraph 2 on page 3?
Q. Correct.
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A. "For good and valuable consideration receipt of
which the parties hereby acknowledge, Clark Canyon agrees to
transfer to Idaho Power ownership of all environmental
attributes associated with the facility beginning with the
first hour of the first day of the 11th contract year and for
the remaining term of the FESA."
Q. When you signed this, I assume you reviewed it?
A. I did.
Q. And if Idaho Power believed that it owned the
RECs, why would you sign a contract in which the QF developer
transfers them to you in exchange for good and valuable
consideration?
A. I've never said that we own them. That is
undecided and that is a matter of this proceeding.
Q. What was the good and valuable consideration paid
by Idaho Power for ownership of the RECs?
A. I'm -- I'm not sure that I know. It's more a
legal term. I'm not sure I can --
Q. That means, what did you pay? How much money
exchanged hands?
A. I don't know the answer to that.
Q. Do you know of any?
A. I don't think any was.
Q. Pardon me?
A. I don't think any was. I don't know.
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Q. Wasn't the good and valuable consideration for
this project Clark Canyon's forbearance from accepting a clause
that clouded title to the RECs?
MR. WALKER: Objection, Madam Chair: The
agreement speaks for itself, and I think everybody could look
at it and make their own determination. The Commission can
make its own determination.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: I think I'm done, Madam Chair.
COMMISSIONER SMITH: Good choice.
MR. RICHARDSON: Thank you, Ms. Grow.
COMMISSIONER SMITH: Ms. Nelson.
MS. NELSON: No questions, Madam Chair.
COMMISSIONER SMITH: Mr. Otto.
MR. OTTO: I do have just one or two questions.
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BY MR. OTTO:
Q. So, Mr. Richardson has laid -- covered the ground
quite well, but you mentioned in your conversation with him
about being concerned of the specter of federal or -- that was
my term, "specter," but of the possibility of federal or state
renewable portfolio standards. And do you recall that prior
testimony?
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A. Yes.
Q. So as part of the management team, does Idaho
Power have an official position on either promoting or opposing
that kind of legislation at the state or federal level?
A. We don't have an official position. We would say
we think we're one of the original renewables in being hydro
based, and then when you couple that with all of the renewables
we buy through PURPA, we have one of the highest percentages of
renewables in our portfolio without one. So whether that will
remain and we won't have one in this state or the federal
government will or will not act, I don't know.
Q. So you don't have a position on whether this
should be a formalized reporting process?
A. A formalized reporting?
Q. Well, a formalized way of tracking how much
renewable energy is a part of your portfolio.
A. Well, again, we do so informally, but as one of
the previous witnesses talked about, the definition of a REC
varies widely from state to state, so it depends on how you're
talking about accounting.
For example, hydro with impoundments in some
states are not included. We believe it should be.
Q. Fair enough. So I guess this is getting at the
question, the obvious question, is why do you want the RECs?
A. Well, again, it is -- we believe that by virtue
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COMMISSIONER
COMMISSIONER
Redirect, Mr
MR. WALKER:
COMMISSIONER
MR. WALKER:
KJELLANDER: No.
SMITH: Nor I.
Walker.
No redirect, Madam Chair.
SMITH: Thank you, Ms. Grow.
Madam Chair, may Ms. Grow be
of these resources being renewable and us having to pay a very
high price for it, we believe that the customers are entitled
to the attribute that allowed it to become a QF in the first
place.
Q. So then do you believe you're paying for more
than just the capacity and energy?
A. I don't know that it's so much that. I believe
that the attribute itself is the very nature of the generation
we're receiving.
MR. OTTO: And I'll leave it there. Thank you.
No further questions.
COMMISSIONER SMITH: Ms. Sasser, did you have
questions?
MS. SASSER: No questions, Madam Chair.
COMMISSIONER SMITH: Questions from the
Commissioners.

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excused?
COMMISSIONER SMITH: Is there any objection to
excusing Ms. Grow for the remainder of the proceeding? Seeing
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none, she will be excused.
(The witness left the stand.)
MR. MILLER: Madam Chairman.
COMMISSIONER SMITH: Mr. Miller.
MR. MILLER: I don't mean to interrupt
Mr. Walker's presentation, but during Mr. Richardson's
examination it appeared, to me, there might be some uncertainty
as to the whereabouts or status of Exhibit 2201.
The exhibit was filed on July 20th, along with
the legal briefs. Ridgeline does not have a witness, but we
have previously, in our intervention papers, requested the
Commission to take official notice of that, and yesterday I
filed an Affidavit establishing the foundation for having it
marked.
So I just wanted to be sure that Exhibit 2201 is
available to the Commission. I just looked: It appears to be
on the Internet docket page. If possible, I'd like to resolve
this before Ms. Park testifies, as I will likely have some
questions for her on that exhibit.
COMMISSIONER SMITH: So, Mr. Miller, we do have
that, that you filed I think with your brief.
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MR. MILLER: Correct.
COMMISSIONER SMITH: And I do have your
Affidavit.
MR. MILLER: Okay.
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COMMISSIONER SMITH: And since there was no
witness for it to come in through, I wasn't quite sure what to
do with it. But so those of you who are searching for it, it
will be with Mr. Miller's brief, and the Affidavit was filed
the 6th. Was that yesterday?
MS. SASSER: Yes, it was.
COMMISSIONER SMITH: And the exhibit is a copy of
the firm energy sales agreement between Idaho Power Company and
Rockland Wind Project, LLC. So I would not imagine anybody
would object.
MR. WALKER: Madam Chair, Idaho Power does not
object to that. And, in fact, that contract can be found under
its corresponding case number here at the Commission when it
was filed and approved as well, so I don't even know that it's
necessary to admit it separately as an exhibit. It could be
noticed as part of the Commission's files and records.
COMMISSIONER SMITH: But I think it is better to
have it as an exhibit so that the record is complete within
itself, you know, on the really outside possibility that
someone might want to go to the Supreme Court. I recognize
that that's very remote. It could happen. So that should
clear up Exhibit 2201.
(Ridgeline Exhibit No. 2201 was premarked
for identification.)
MR. MILLER: And can I make just one additional
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o
1 side note?

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COMMISSIONER SMITH: You may.

3
MR. MILLER: As the Commission noticed, I didn't,
in the interest of avoiding duplication, ask questions of the

5 last witness or of the preceding witness on the topic of RECs.

6
I would just like to note that my client, Renewable Northwest

7 Project, has a strong position on RECs, which is set forth in

8
its legal brief filed on July 20th, and the lack of

9 cross-examination on that issue should not be interpreted as

10 reflecting any retreatment on that position.

11
COMMISSIONER SMITH: Nor will any be presumed.

12 MR. MILLER: Okay.
S 13
(Whereupon, Volume III of this transcript

14 is completed.)
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