20120131Hieronymus Direct.pdf

RECEIVED
2012 JAN 3 l PM 3: 23
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'S
REVIEW OF PURPA QF CONTRACT
PROVISIONS INCLUDING THE SURROGATE
AVOIDED RESOURCE (SAR) AND
INTEGRATED RESOURCE PLANNING (IRP)
METHODOLOGIES FOR CALCULATING
PUBLISHED AVOIDED COST RATES.
CASE NO. GNR-E-ll-03
I DAHO POWER COMPANY
DIRECT TESTIMONY
OF
WILLIAM H. HIERONYMUS
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 utili ties. I have worked extensively with utili ties
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 legislati ve bodies on these topics and on policy matters
23 such as price regulation, competi ti ve market design, market
24 power, the prudence of utility decisions, stranded costs,
25 and so forth. In the 1980s I helped utilities and
HIERONYMUS, DI 1
Idaho Power Company
1 regulators in complying with the requirements of Public
2 Utility Regulatory Policies Act of 1978 ("PURPA"). This
3 included compliance with PURPA Section 210 that governed
4 purchases from and sales to qualifying facilities ("QF").
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
HIERONYMUS, DI 2
Idaho Power Company
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 al ternati ves 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.
HIERONYMUS, DI 3
Idaho Power Company
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 resul ts 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 QF 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.
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HIERONYMUS, DI 4
Idaho Power Company
1 II. SUMY OF CONCLUSIONS AN RECOMMNDATIONS
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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HIERONYMUS, DI 5
Idaho Power Company
1 been in the other direction, ratepayers would have had a
2 windfall, at least until proj ects 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
HIERONYMUS, DI 6
Idaho Power Company
1 condi tions 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 utili ties and the lack of
7 competitive or transparent markets for power. Unhappy
8 experience wi th administratively set avoided costs in the
9 early years after PURPA caused FERC and many utili ties 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.
HIERONYMUS, DI 7
Idaho Power Company
1 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
13 capaci ty costs may reflect changes in the resource plan as
14 it is adj usted 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 proj ects of
24 100 kilowatts ("kW") or less, but many states have extended
25 fixed offers to much larger units. In many instances, the
HIERONYMUS, DI 8
Idaho Power Company
1 schedule is based on a proxy unit. Use of such schedules
2 should be sharply limited for two reasons:(a) the price
3 deri ved from a single proxy unit may be very
4 unrepresentati ve of the value of a particular QF and (b)
5 such inaccurate schedules can contribute to substantial
6 excesses of QF proj ects demanding contracts. This problem
7 is best mitigated by a combination of limiting the size of
8 proj ects 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.
HIERONYMUS, DI 9
Idaho Power Company
1 11.There now are multiple ways of setting
2 PURPA 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 administrati ve 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 qui te dissimilar proxy unit. While more complicated than
19 proxy unit methods, simulation is within the capability of
20 all utili ties and is particularly appropriate when non-
21 dispatchable , intermittent resources are a maj or 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
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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, dispatchabili ty,
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
HIERONYMUS, DIll
Idaho Power Company
1 particularly important that consumers not take on price
2 risk for QF power that is not even used to serve them, but
3 rather is sold into the interchange market.
4 e.Seek to limit purchases of
5 unneeded QF energy and capacity. Quantity-limited requests
6 for proposals ("RFP") and auctions is one way to do this.
7 Properly reflecting the value of the specific QFs is
8 another. For price rationing to work, it is necessary that
9 avoided costs be reset as often as is necessary to reflect
10 the impact of prior QFs on avoided energy and capacity
11 values. Rationing based on pricing aside, this also is
12 necessary if avoided costs are to be computed properly.
13 FERC has noted that the attraction of too much QF power is
14 a signal that prices being paid are too high and should be
15 reduced. Including the successive amounts of QF power in
16 the calculation is one way to do this, albeit not
17 necessarily sufficiently.
18 Q.You stated earlier that you had reviewed and
19 would comment on IPC's proposed changes to its QF avoided
20 cost rates and tariff provisions. What do you conclude
21 based on that review?
22 A.I have reviewed Idaho Power's proposal for
23 revising the Idaho avoided cost calculation and contract
24 terms. My review is at a relatively high level and does
25
HIERONYMUS, DI 12
Idaho Power Company
1 not extend to some of the details in it. I conclude the
2 following:
3 1.The fact that QFs 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
HIERONYMUS, DI 13
Idaho Power Company
1 hydroelectric proj ects 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 proj ects 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 uni versal practice in the Regional Transmission
13 Organization ("RTO") 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
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 proj ect elsewhere or build it
6 in Idaho but not request a QF contract, instead selling
7 into the commercial market. A further al ternati ve is to
8 sell it to IPC under its existing non-firm QF contract that
9 pays the proj ect 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 proj ects "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 utili ties 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
HIERONYMUS, DI 15
Idaho Power Company
1 relating to on-selling QF power into interchange markets,
2 contract length is somewhat less sensi ti ve.
3 7.The Idaho utili ties currently
4 differentiate between fueled and non-fueled QFs 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 QF
8 developers and the utili ties' customers since it reasonably
9 hedges the prices paid by the utili ties 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 8.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 competi ti ve markets through to
HIERONYMUS, DI 16
Idaho Power Company
1 QFs in lieu of paying administratively determined avoided
2 cost rates, mayor 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 al ternati ve to administratively set
7 avoided costs now or at such later time as the facts
8 warrant.
9 III. PURPA PUROSES AN HISTORY
10 Q.What is the origin of the requirement to
11 purchase power from QFs?
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 Proj ect 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.
HIERONYMUS, DI 17
Idaho Power Company
1 Section 210 of PURPA is a relatively brief portion
2 of the bill that mandated arrangements under which electric
3 utili ties 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 "i t determines necessary to encourage cogeneration and
7 small power production and to encourage geothermal
8 facilities of not more than 80 megawatts capacity.,,1
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 reliabili ty of such facilities during emergencies) ."
19 The portion dealing with rules concerning rates to be paid
20 to such facilities by electric utili ties:
FERC's implementation treated the cut-off for small power
facili ties 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 utili ties 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,
but continued to apply an 80 MW limit on the grounds that this always
had been its policy.
HIERONYMUS, DI 18
Idaho Power Company
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shall insure that, in requiring any
electric utility to offer to purchaseelectric energy from any qualifying
cogeneration facility or qualifying small
power production facility, the rates for
such purchase:
(1) Shall be just and reasonable to
the electric consumers of the
electric utility and in the public
interest, and
(2) Shall not discriminate against
qualifying cogenerators or
qualifying small power producers.
No such rule prescribed under subsection
(a) of this section shall provide for a
rate which exceeds the incremental cost
to the electric utility of al ternati ve
electric energy.
The "incremental cost of al ternati ve electric
24 energy" was subsequently defined:
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For purposes of this section, the term"incremental cost of al ternati ve electric
energy" means, with respect to electricenergy purchased from a qualifying
cogenerator or qualifying small powerproducer, the cost to the electric
utili ty of the electric energy which, but
for the purchase from such cogenerator or
small power producer, such utility would
produce or purchase from another source.
Q.Did the Act show Congressional intent to
37 subsidize QFs?
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
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 di vergence 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
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 proj ects. 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 proj ects. These standard rates are
11 expressly permitted to vary by type of proj ects.
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 ( (§294. 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
HIERONYMUS, DI 21
Idaho Power Company
1 al ternati ve being offered. 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 PURPA
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 RM88-06 (1988), FERC clarified that the prices offered at
signing could be formula rates, not fixed prices.
3 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."
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 utili ty 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:..."
24
25
HIERONYMUS, DI 23
Idaho Power Company
1
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2.The availability of capacity or
energy from a qualifying facility
during the system daily and
seasonal peak periods, including:
i. The ability of the utility todispatch the qualifying
facili ty;
ii. The expected or demonstrated
reliabili ty of the qualifyingfacility;
iii. The terms of any contract or
other legally enforceable
obligation, including theduration of the obligation,termination notice
requirement and sanctions for
non-compliance;
i v. The extent to which scheduledoutages of the qualifyingfacili ty can be usefully
coordinated wi th scheduledoutages of the utili ty' sfacilities;
v. The usefulness of energy and
capacity supplied from a
qualifying facility during
system emergencies, including
its ability to separate its
load from its generation;
vi. The individual and aggregate
value of energy and capacity
from qualifying facilities onthe electric utility's
system; and
vii. The smaller capacityincrements and the shorterlead times available wi th
additions of capacity from
qualifying facilities; and
HIERONYMUS, DI 24
Idaho Power Company
1
2
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4
5
6
7
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3. The relationship of theavailabili ty of energy or capacityfrom the qualifying facility as
derived in (the methodology basedon i through vii) to the ability
of the electric utility to avoidcosts, including the deferral of
capaci ty addi tions and the
reduction of fossil fuel use; and
4. The costs or savings resulting
from variations in line losses
from those that would have existed
in the absence of purchases from a
qualifying facili ty, if thepurchasing electric utility
generated an equivalent amount of
energy itself or purchased anequivalent amount of electric
energy or capacity.
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
HIERONYMUS, DI 25
Idaho Power Company
1 implementation was resolved, and the mid-198 Os. This was
2 an era when many state commissions were distrustful of
3 utili ties' 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 utili ties 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 competi ti ve 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
4 Short-term contracts for as available power are an exception to
this generalization since such power was, per requirement of the Act,
paid the utili ties actual avoided cost at the time of deli very. Even
this actual price was determined by methods created through regulation
since there was little if any price transparency.
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
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
5 The notable exception to this generalization was California.
Many thousands of small wind turbines were builtin three wind farm
areas, at least partly as a result of non-PURPA state subsidies.
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 utili ties 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 QF 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" avoidedcost rates.
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 size
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 1990.7
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
7 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/whatwedo/PublicPolicyAdvocacy/StateRegulation/Docume
nts/purpa.pdf, at p. 16.
HIERONYMUS, DI 30
Idaho Power Company
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 utili ties in New York. 8
4 This was argued to be acceptable because it had
5 encouraged significant quanti ties 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 un til 19 95 . 9
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.
9 Ibid at page 15.
HIERONYMUS, 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.
1 7 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
HIERONYMUS, DI 32
Idaho Power Company
1 conducted, FERC issued three interrelated NOPRs10 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
11 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 subj ect 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.
11 The Independent Power Producer NOPR proposed streamlining
regulation of a proposed new type of generators that would not be
subj ect 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.
HIERONYMUS, DI 33
Idaho Power Company
1 provisions to police self-dealing in utili ties' selection
2 between affiliated and unaffiliated generation proposals.
3 Among those opposing the NOPRs 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.Notwi thstanding the fate of the NOPRs, 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, RM8-6
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
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 utili ties were organized into the following topics:
6
7
8
9
1.Inappropriate Methods for Determining
Avoided Costs.
a. Quanti tati ve Limits on Capacity
10 Needs.FERC characterized this as the most common
11 complaint. The 1980s were a period of substantial excess
12 capaci ty in much of the U. S., but utili ties 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.
HIERONYMUS, DI 35
Idaho Power Company
1 approach13 and other avoided cost methods also could lead to
2 unlimited capacity commitments.
3 b.Failure to Take into Account
4 Quali tati ve Characteristics. In its 1980 regulations
5 implementing PURPA Section 210, FERC had listed several
6 quali tati ve factors that must be considered but need not be
7 taken into account in state implementations. Comments
8 cri ticized 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.
HIERONYMUS, DI 36
Idaho Power Company
1 utili ties, 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 al ternati ve. Others noted that at
10 times they had to back down low variable cost baseload
11 uni ts 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.
HIERONYMUS, DI 37
Idaho Power Company
1 4. Mul tistate Utili ties . 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 maj or 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
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 utili ties. The
17 cri teria 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 avoided24 capacity cost appear to result in part25 from a lack of attention to the26 relationship between the characteristics27 of the QFs involved and the quality,
HIERONYMUS, DI 38
Idaho Power Company
1 quanti ty, or source of the capacity
2 avoided. For utilities to use QF power3 instead of building new plants or
4 purchasing power, it is necessary for the
5 quali tati ve characteristics of QFs and6 utili ties' plans to at least roughly7 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 current18 regulations has been read as allowing19 open-ended standard offers to all QFs.20 It is clear, however, that the avoided21 cost standard requires that QFs be paid22 for only the capacity cost that a utility23 avoids because of the presence of QFs24 To address this problem, the25 Commission proposes to amend its26 regulations to assure that (under) such27 standard offers capacity payments28 would not be available once the29 purchasing utility's capacity needs have30 been satisfied. (p. 48).
3132 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 proj ect size of 1 MW.
HIERONYMUS, DI 39
Idaho Power Company
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 QF to the purchasing
11 utility or its ratepayers. It also noted that fixed rates
12 could reduce transaction costs, which could be important
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, the18 term "fixed-Price contract" refers to any19 legally enforceable obligation wherein20 the rates for purchases by a utility are21 established in advance of the time of22 purchase. The fixed price may be a23 single, uniform rate per kilowatt or24 kilowatt-hour for all power, including a25 fixed formula rate, or a complex schedule26 of time-differentiated rates and other
27 payments. The contract's term may range28 from decades to months. (p.56)
2930 From this description, and in particular the
31 inclusion of formula rates , it is reasonable to interpret
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 utili ty 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:
13 Most of the problems with efficiency14 associated with long term fixed-price15 contracts flow from the rigidities such16 contracts impose on price and quantity of17 electrici ty. These problems can be18 ameliorated by relaxing restriction on19 price or quantity, or by shortening the20 contract period . Quantity flexibility21 implies QF dispatchability. If the22 utility is unable to "turn the QF off" it23 may be unable to take advantage of
24 economy energy, or it may have to back25 down its more efficient plants to buy26 higher priced QF energy. If the utility27 cannot "turn the QF on" it may not be28 able to take advantage of the QF's
2 9 capacity when it is most needed during30 peak demand or a system emergency.31 (pp.61-62)
32
33 The Commission proposes to amend its34 regulations in order to allow for greater35 pricing flexibility. Pricing flexibility36 may take several different forms. For
HIERONYMUS, DI 41
Idaho Power Company
1
2
3
4
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6
7
8
9
10
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12
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18
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21
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31
32
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34
35
36
37
38
39
instance a contract could provide QFs
wi th a price floor applicable to all the
power supplied to the utility, but still
provide for higher variable unit prices
reflecting daily or seasonal periods.
The price floor would provide the revenue
stream necessary for the QF to secure
financial support while the pricevariabili ty would induce the QF to
maximize deliveries in peak-load periods
when the utili ty values addi tionalsupplies most. Of course, the price
floor should not exceed the minimum value
of the utili ty' s avoided cost.
Similarly, a contract could provide for a
two part price a fixed payment for
capaci ty and an energy price for power
delivered. The QF would be assured a
minimum revenue stream based on the value
of its capacity. The variable energy
component would allow the utility to
dispatch the QF capacity only when it waseconomic. Whatever the pattern of
contract payments, rates for purchases
from QFs should always reflect how well
the characteristics of the supplier's
power match the purchasing utility's need
To avoid problems such as thoseassociated with take-or-pay contacts inthe natural gas industry, 14 the
Commission wishes to stress the danger of
including forecasted fuel costs in the
fixed rate structure of long-term
contracts, especially in combination with
the specification of minimum purchases
quanti ties. The Commission also
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
utili ties 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.
HIERONYMUS, DI 42
Idaho Power Company
1
2
3
4
5
seasonalstructures
(pp. 65-66. )
rates
for
in flexible pricinglong-term contracts.
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 QF power by
15 1985, whereas the amount actually installed (i. e., not
16 including contracts requested or contracts signed with
17 facili ties 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.
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 di.fficul ty 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 utili ties 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 rate15 or standard offer, QFs offer much more16 capacity than the utility needs, a17 prospective adjustment to the rate should18 be considered for contracts that have not19 yet been entered into. If the excess20 amount of offered capacity is large, then21 the state regulatory authority or non-22 regulated electric utility may want to23 re-examine its method for determining24 avoided capacity costs to see if some25 efficient alternatives available to the26 utility were not considered. The27 Commission believes that if QFs offer28 capacity in amounts greatly exceeding the29 utility's capacity needs, then the rate30 for purchase of that capacity was31 probably not set in reference to the cost32 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.
HIERONYMUS, DI 44
Idaho Power Company
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
al ternati ve. A rate that does not
reflect the cost of the utility's most
efficient alternative source of capacity
is excessive, and should be adjusted
downward. . . .
Moreover, even a properly calculated
standard offer will not remainappropriate indefini tely. Theal ternati ve upon which a rate is figured
comprises a certain block of capacity.
If this block is fully satisfied, a
change in the standard offer may be
necessary.
The Commission recognizes the difficulty
of administratively setting avoided cost
rates that induce QFs to supply capacity
in amounts that exactly match a utility'sneeds. Obviously, the signing of
contracts with QFs cannot and should not
be postponed until a rate has been set
that successfully matches the amount of
QF power with the capacity needed by the
purchasing utility. Rather, in the
event that it becomes clear that a rate
is eliciting more QF power than the
utility needs, the state regulatory
authorities or non-regulated electric
utility could suspend the rate. (pp. 41-
42. )
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
4 0 administratively set offers:
HIERONYMUS, DI 45
Idaho Power Company
1 Admi ttedly , administratively calculated
2 avoided cost is unlikely to successfully3 resul t 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 among8 QFs.
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 concluded15 that purchases from other QFs fall within16 the meaning of "another source" under the17 section 210 (d) definition of "incremental18 cost of alternative energy. "If a19 utility does not purchase from one20 particular QF, it certainly has the
21 option of purchasing power from other QFs22 Obviously, if a utility23 purchases power from a QF at a price that
24 is higher than a rate for comparable25 power available from another source,26 whether it is another utility or another27 QF, the purchasing utility's customer28 rates would be higher than they would
29 have been had the purchase not been made30 and the purchasing utility had purchased31 from that other source. (pp. 35-36) ,
3233 The Bidding NOPR, RM88-0S
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:
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 authori ties and nonregulated electric
5 utili ties 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). A10 bidding program is a formally organized11 market to acquire incremental supplies of12 electricity. This proposed rule13 sanctions the use of bidding as a14 procedure for purchasing electricity for15 purchasing electricity from QFs.
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 al ternati ves, 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 bidding16 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 It states (page 15) that Maine, Massachusetts, and California
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.
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
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 notwi thstanding its statements elsewhere that bidding could
15 be used to meet only part of the requirements. Non-QF
16 proj ects that were not selected, including proj ects
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
HIERONYMUS, DI 48
Idaho Power Company
1 purposes. However, it reasoned that the PURPA's "must buy"
2 requirement did not extend to paying capacity payments to
3 QFs that were unneeded and not selected as being economic
4 in the bidding procedure. Hence, while the utility still
5 would have to pay an administratively determined energy
6 payment to QFs that did not have accepted bids, the QFs
7 would not be entitled to capacity payments.
8 Left unsaid was the expectation that few QFs would
9 be built if they did not receive capacity payments. At the
10 time of the NOPR, avoided energy would typically be from
11 coal or gas-fired capacity (owned or purchased) and priced
12 at relatively low marginal costs. This would be true all
13 of the time if the administratively determined energy price
14 for QFs not selected in response to the RFP was based on a
15 proxy unit, and much of the time even if IRP-type methods
16 were used. Hence, most QFs would earn quite little from
17 these avoided energy-only payments. By limiting the amount
18 of capacity/energy production capability purchased via
19 bidding to the amount that the utility needed and limiting
20 the right to earn avoided capacity cost to the winning
21 bidders, the inefficiency otherwise inherent in the
22
23
24
25
HIERONYMUS, DI 49
Idaho Power Company
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 proj ects 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"
17 "PURPA 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."
íEmphasis added; p. 37.)
HIERONYMUS, 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 maj ori ty 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.Notwi thstanding that the NOPRs were not
23 adopted, were the concepts contained therein subsequently
24 put to use?
25
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 subj ect.
14 Several states adopted competi ti ve bidding as the
15 primary means of procurement shortly after the NOPR.
16 Within a decade, the "Genco/Disco" model was adopted for
17 more than half the load-serving utili ties 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
HIERONYMUS, Dr 52
Idaho Power Company
1 evolution of privately sponsored generation as an
2 al ternati ve 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
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
HIERONYMUS, DI 54
Idaho Power Company
1 The consequence of exemption is that proj ects that
2 would have qualified as QFs 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 it18
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 utili ties 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 utili ties 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.
HIERONYMUS, DI 55
Idaho Power Company
1 utili ties that remained subj ect 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 competi ti ve 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.
HIERONYMUS, DI 56
Idaho Power Company
1 contracts or the shifting of price risk from the generator
2 to a utility. Capaci ty 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
HIERONYMUS, DI 57
Idaho Power Company
1 acti vi ty, 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 al though 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 JUISDICTIONS
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 PURPA, developers often have been allowed to
split the farms up into projects that are small enough to qualify.
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 ("EEI") 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 utili ties
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 QFs.
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 Na ture of
Marginal And Avoided Costs in Ratemaking; A Survey, NERA, January 1992.
HIERONYMUS, 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. Despi te
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.
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.Capaci ty 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
relati ve 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
construction of long lead time,
baseload stations was initiated.
be expected in the mid-1970s when
large (primarily coal and nuclear)
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 spli t-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 (Le., 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.
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 QFs 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 quanti ties 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 EEI 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 paper27 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.
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 maj or 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 EEI 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 proj ected capacity and
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. Adj ustments generally included modifying
4 capaci ty 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 EEI
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.
HIERONYMUS, DI 65
Idaho Power Company
1 Implicitly, the methodology assumes that the existence of
2 the QF does not affect the utili ties' 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 wi thin 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 competi ti ve options for cogeneration and small power
28 An exception is that in the component/peaker 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.
HIERONYMUS, DI 66
Idaho Power Company
1 facilities that motivated Congress to include Section 210
2 in PURPA.
3 The EEI 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 limi t 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
HIERONYMUS, 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 QFs 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 maj or 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,
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.
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 less, many states allowed standard offer
12 rates for larger proj ects. As noted previously, California
13 made its standard offer rates available to all proj ects.
14 Since the rates were very attractive to developers, the
15 state was swamped with proj ects.
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 QFs 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 quanti ties 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 utili ties. While dispatchabili ty had been one of the
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 al ternati ve 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
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
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 ("S04"). S04 fixed
21 forecasted energy prices just before gas prices collapsed
22 and hence was highly profitable, particularly but not
23 uniquely for gas-fired cogeneration. S04 had no ceiling
24 quantity amount and, according to Southern California
25 Edison, by early 1987 caused total QF contracts in
HIERONYMUS, DI 73
Idaho Power Company
1 California to rise to 16,000 MW, notwithstanding that S04
2 existed only from April 1983 until it was suspended in
3 September 1984. S04 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 proj ects 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 utili ties to apply for exempt status, which would result in
23 existing QFs losing PURPA as a basis for demanding
24
25
HIERONYMUS, DI 74
Idaho Power Company
1 contracts altogether.3o 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 utili ties, 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 QFs 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.
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, anew, competi ti ve 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 utili ties to run competi ti ve, transparent RFOs for CHP
14 resources. It puts CHP resources into a process similar to
15 the competi ti ve 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.
HIERONYMUS, DI 76
Idaho Power Company
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 proj ects 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 submi tted an offer in the RFO or seeks al ternati ve
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 proj ect 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 D. 07-09-040, with Firm
Capacity of $41.22/kW-yr
Capacity pricing is pursuant to
Capacity at $91.97 /kW-yr and As-Available
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.
HIERONYMUS, DI 77
Idaho Power Company
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 SRAC 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 capaci ty). 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 subj ect to non-
19 availabili ty 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 SRAC price is set based on 12 months of forward
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 RA,
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 utili ties to procure an initial 1,000 MW through RAM.
19 Under the market-based pricing in the RAM, sellers compete
20 for a contract in a renewable auction mechanism, bids are
33 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.
HIERONYMUS, DI 79
Idaho Power Company
1 selected by least-cost price first until the auction
2 capaci ty 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 competi ti ve
12 solici tation. 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 quanti ties 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 proj ects 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
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 Effecti vely, 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 proj ects. 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 obj ecti ves 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 proj ects of less than 1.5 MW. However, eligibility under
25 this program is severely quantity limited.
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 wi th 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 utili ties 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 QFs 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.
HIERONYMUS, DI 82
Idaho Power Company
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 wi thin 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
34 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 utili ties 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 wi thin 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
HIERONYMUS, DI 84
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 utili ties 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 utili ties
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. SPS continues, therefore, to be required to buy
25 QF power under PURPA. However, both the Texas and Oklahoma
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.How does Oregon use market prices to set
12 avoided costs?
13 A.Oregon distinguishes between avoided cost
14 methods for near-term periods when utili ties 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
HIERONYMUS, DI 86
Idaho Power Company
1 IRP method. It offers standard contracts for units up to
2 fi ve 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 al ternati ve, 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 utili ties
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 utili ties using
13 auction or RFP methods to set prices?
14 A.Yes. An example is Georgia using competi ti ve
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
HIERONYMUS, DI 87
Idaho Power Company
1 the utility's next unit as the proxy, in that the proxy
2 uni t 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.
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 utili ties 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 utili ties avoided unit.
25 Necessarily, this unit will have a later on line date than
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 recei ves 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 utili ties
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 utili ties still can rely on competi ti ve procurement
13 for limited quanti ties of energy and rej ect 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 capaci ty 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
24
25
HIERONYMUS, DI 90
Idaho Power Company
1
2
V.CURNT AVOIDED COST OPTIONS AN RECOMMNDATIONS
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.Administrati ve/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 utili ties
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
2 6 capital cost of the peaker, preferably calculated net of
HIERONYMUS, DI 91
Idaho Power Company
1 energy and ancillary services net revenues and adj us ted 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 RFP /Auction.The utility holdsa.
9 competi ti ve 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 limi ted 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
HIERONYMUS, DI 92
Idaho Power Company
1 relevant competi ti ve 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 RTOs 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
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
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
35 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 subj ect of the auction, at least at that time.
HIERONYMUS, DI 94
Idaho Power Company
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.
HIERONYMUS, DI 95
Idaho Power Company
1 Q.Is it possible to adjust the proxy unit-
2 deri ved 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 uni t 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
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
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 photovol taic 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 utili ties were to pass
HIERONYMUS, DI 97
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 adj ustments), the resultant avoided costs
4 would be identical to the revenues that the QF would
5 recei ve if Idaho were part of a market in which utili ties
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
13 is essentially the result that would ensue if the Idaho
14 utili ties 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 utili ties 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
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 utili ties 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-QF
6 sources. If, as it likely must be, market pricing is
7 ei ther 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. Qui te simply, that PURPA never was intended to
14 subsidize QFs. If the prices that utili ties 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 proj ect 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.
HIERONYMUS, DI 99
Idaho Power Company
1 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 PURPA should be taken into
9 account, such as firmness, dispatchability, fuels
10 di versi ty, 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,
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
HIERONYMUS, DI 100
Idaho Power Company
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 utili ties 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
HIERONYMUS, DI 101
Idaho Power Company
1
2
VI. SUGGESTIONS CONCERNING AVOIDED COST PRICING
BAED ON ADMISISTRATlVE 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 only for 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 proj ects), 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
HIERONYMUS, DI 102
Idaho Power Company
1 amount of QF capacity that is in process. Additions of QF
2 capaci ty 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 (ei ther individual proj ects or aggregates of proj ects), the
13 effect of the resource on marginal costs and the need for
14 capaci ty 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
1 7 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 costs and it is improper for customers to shoulder
25 such risks for power that does not benefit them.
HIERONYMUS, DI 103
Idaho Power Company
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 proj ect 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.
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
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
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 proj ects
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 proj ects
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 builtin
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
HIERONYMUS, DI 106
Idaho Power Company
1 the financial risks of the proj ect 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. Proj ect 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 excessi ve 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
HIERONYMUS, DI 107
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
37 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/mmBTU. 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.
HIERONYMUS, DI 108
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 utili ties 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
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
25
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
11 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
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
1 7 competitive markets. However, so long as Idaho utili ties
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 PURPA Section 210 responsibilities sometime in the future.
25 However, under PURPA as modified by EPAct, exemption
HIERONYMUS, DI 111
Idaho Power Company
1 requires satisfying FERC that QFs will have access to a
2 competi ti ve 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 capaci ty 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 adj acent
22 markets.I have discussed instances where this is done.
38 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.
HIERONYMUS, DI 112
Idaho Power Company
1 An al ternati ve 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 di verge 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 capaci ty-
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
HIERONYMUS, DI 113
Idaho Power Company
1 two, and only two consequences: assuring that QFs 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
10 being offered in Idaho than has been offered in recent
11 years. This is an appropriate outcome and is fully
12 consistent with the letter and intent of PURPA. If Idaho
13 determines that it needs more renewable generation than
14 PURPA produces, there are other policy tools that can be
15 used to cause renewable generation to be constructed,
16 including, for example, set-aside procurements limited to
17 renewables such as were approved in the past year for
18 California.
19 Q.Does this complete your testimony at this
20 time?
21 A.Yes, it does.
22
23
24
25
HIERONYMUS, DI 114
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. GNR-E-11-03
IDAHO POWER COMPANY
HIERONYMUS, 01
TESTIMONY
it EXHIBIT NO.6
Resume of Willam H. Hieronymus
WILLIAM H. HIERONYMUS Ph.D. Economics
University of Michigan
MA Economics
University of Michigan
BA Social Sciences
University of Iowa
Wiliam Hieronymus has consulted extensively to managements of electricity and gas companies, their
counsel, regulators, and policymakers. His principal areas of concentration are the economics, structure
and regulation of network utilties and associated management, policy, and regulatory issues. Dr.
Hieronymus has spent the last twenty years working on the restructuring and privatization of utilty
systems in the U.S. and internationally. In this context he has assisted the managements of energy
companies on corporate and regulatory strategy, particularly relating to asset acquisition and divestiture.
He has testified extensively on regulatory policy issues and on market power issues related to mergers
and acquisitions. In his thirty-odd years of consulting to this sector, he also has performed a number of
more specific functional tasks, including analyzing potential investments; assisting in negotiation of power
contracts, tariff formation, demand forecasting, and fuels market forecasting. Dr. Hieronymus has
testified frequently on behalf of energy sector clients before regulatory bodies, federal courts, arbitrators
and legislative bodies in the United States, the United Kingdom and Australia. He has contributed to
numerous projects, including the following:
ELECTRICITY SECTOR STRUCTURE, REGULATION, AND
RELATED MANAGEMENT AND PLANNING ISSUES
U.S. Market Restructuring Assignments
· Dr. Hieronymus serves as an advisor to the senior executives of electric utilities on restructuring and
related regulatory issues, and he has worked with senior management in developing strategies for
shaping and adapting to the emerging competitive market in electricity. Related to some of these
assignments, he has testified before state agencies on regulatory policies and on contract and asset
valuation.
1
Exhibit No.6
Case No. GNR-E-11-03
W. Hieronymus, IPC
Page 1 of 8
Resume of Wiliam H. Hieronymus
. For utilities seeking merger approval, Dr. Hieronymus has prepared and testified to market power
analyses at FERC and before state commissions. He also has assisted in discussions with the
Antitrust Division of the Department of Justice and in responding to information requests. The
mergers on which Dr. Hieronymus has testified include both electricity mergers and combination
mergers involving electricity and gas companies. Among the major mergers on which he has
testified are Duke-Progress, Duke-Cinergy, NSTAR-Northeast Utilties, Sempra (Enova and Pacific
Enterprises), Xcel (New Century Energy and Northern States Power), Exelon (Commonwealth
Edison and Philadelphia Electric), AEP (American Electric Power and Central and Southwest),
Dynegy-lIinois Power, Con Edison-Orange and Rockland, Dominion-Consolidated Natural Gas,
NiSource-Columbia Energy, E-on-PowerGen/LG&E and NYSEG-RG&E, Iberdrola-Energy East,
Texas Energy Futures-TXU, Exelon-NRG, GDF/Suez and FirstLight and MacQuarie-Puget Sound.
He also submitted testimony in mergers that were terminated, usually for unrelated reasons,
including EEG (Exelon and PSEG), Constellation-FPL Energy, Entergy-Florida Power and Light,
Northern States Power and Wisconsin Energy, KCP&L and Utilicorp and Consolidated Edison-
Northeast Utilities. Testimony on similar topics has been filed for a number of smaller utility mergers
and for numerous asset acquisitions. Dr Hieronymus has also assisted numerous clients in the pre-
merger screening of potential acquisitions and merger partners.
. For utilties seeking to establish or extend market rate authority, Dr. Hieronymus has provided scores
of analyses concerning market power in support of submissions under Sections 205 and/or 206 of
the Federal Power Act.
. For utilities and power pools engaged in restructuring activities, he has assisted in examining various
facets of proposed reforms. Such analysis has included features of the proposals affecting market
effciency and revenue adequacy and those that have potential consequences for market power.
Where relevant, the analysis also has examined the effects of alternative reforms on the market
performance, and achievement of the client's objectives. In some cases, these analyses have led to
testimony and/or participation in stakeholder processes.
. For generators and marketers, Dr. Hieronymus has testified extensively in the regulatory
proceedings concerning the electricity crisis in the WECC that occurred during the period May 2000
through May 2001. His testimony concerned, inter alia, the economics of long term contracts
entered into during that period the behavior of market participants during the crisis period and the
nexus between purportedly dysfunctional spot markets and forward contracts. He also provided
testimony and other regulatory support in dockets concerned with economic and physical
withholding, partnership arrangements and bidding and scheduling practices potentially in violation of
the iSO tariff.
. For the New England Power Pool (NEPOOL), Dr. Hieronymus examined the issue of market power
in connection with NEPOOL's movement to market-based pricing for energy, capacity, and ancillary
services. He also assisted the New England utilties in preparing their market power mitigation
proposaL. The main results of his analysis were incorporated in NEPOOL's market power filing
before FERC and in ISO-New England's market power mitigation rules.
. For a coalition of independent generators, he provided affdavits advising FERC on changes to the
rules under which the northeastem U.S. power pools operate.
. For both utilties and generators he has testified on a number of occasions on market mitigation rules
for the New York City load pocket and their relationship to policy goals such as market-based entry.
2
Exhibit No.6
Case No. GNR-E-11-03
W. Hieronymus, IPC
Page 2 of8
Resume of Wiliam H. Hieronymus
Valuation of Utility Assets in North America
· Dr. Hieronymus has testified in state securitization and stranded cost quantification proceedings,
primarily in forecasting the level of market prices that should be used in assessing the future
revenues and the operating contribution earned by the owner of utility assets in energy and capacity
markets. The market price analyses are tailored to the specific features of the market in which a
utility wil operate and reflect transmission-constrained trading over a wide geographic area. He also
has testified in rebuttal to other parties' testimony concerning stranded costs, and has assisted
companies in internal stranded cost and asset valuation studies.
· He was the primary valuation witness on behalf of a western utilty in an arbitration proceeding
concerning the value of a combined cycle plant coming off lease that the utility wished to purchase.
· He assisted a bidder in determining the commercial terms of plant purchase offers as well as
assisting clients in assessing the regulatory feasibility of potential acquisitions and mergers.
· He has testified concerning the value of terminated long term contracts in connection with contract
defaults by bankrupt power marketers and merchant generators.
· In connection with the Western U.S. long term contracts proceeding, he testified with respect to
benchmarking of contracts and to the relationship between market prices and long run marginal
costs of new generation.
Other U.S. Utilty Engagements
· In a recent arbitration proceeding, Dr. Hieronymus testified with respect to contract terms relating to
security provisions for long repaying front-end loaded contract payments.
· Dr. Hieronymus has contributed to the development of several benchmarking analyses for U.S.
utilities. These have been used in work with clients to develop regulatory proposals, set cost
reduction targets, restructure internal operations, and assess merger savings.
· Dr. Hieronymus was a co-developer of a market simulation package tailored to region-specific
applications. He and other senior personnel have conducted numerous multi-day training sessions
using the package to help utility clients in educating management regarding the consequences of
wholesale and retail deregulation and in developing the skills necessary to succeed in this
environment.
· He has made numerous presentations to U.S. utility managements regarding overseas electricity
systems and market reforms.
· In connection with nuclear generating plants nearing completion, he has testified in Pennsylvania,
Louisiana, Arizona, Ilinois, Missouri, New York, Texas, Arkansas, New Mexico, and before the
Federal Energy Regulatory Commission regarding plant-in-service rate cases on the issues of
equitable and economically effcient treatment of plant costs for tariff-setting purposes, regulatory
treatment of new plants in other jurisdictions, the prudence of past system planning decisions and
assumptions, performance incentives, and the life-cycle costs and benefits of the units. In these and
other utility regulatory proceedings, Dr. Hieronymus and his colleagues have provided extensive
support to counsel, including preparation of interrogatories, cross-examination support, and
assistance in writing briefs.
3
Exhibit No.6
Case No. GNR-E-11-03
W. Hieronymus, IPC
Page 3 of8
Resume of Wiliam H. Hieronymus
. On behalf of utilties in the states of Michigan, Massachusetts, New York, Maine, Indiana,
Pennsylvania, New Hampshire, and Ilinois, he has submitted testimony in regulatory proceedings on
the economics of completing nuclear generating plants that were then under construction. His
testimony has covered the likely cost of plant completion; forecasts of operating performance; and
extensive analyses of the impacts of completion, deferral, and cancellation upon ratepayers and
shareholders. For the senior managements and boards of utilities engaged in nuclear plant
construction, Dr. Hieronymus has performed a number of highly confidential assignments to support
strategic decisions concerning the continuance of construction.
. For an eastern Pennsylvania utility that suffered a nuclear plant shutdown due to NRC sanctions
relating to plant management, he filed testimony regarding the extent to which replacement power
cost exceeded the costs that would have occurred but for the shutdown.
. For a major Midwestern utility, Dr. Hieronymus headed a team that assisted senior management in
devising its strategic plans, including examination of such issues as plant refurbishment/life
extension strategies, impacts of increased competition, and available diversification opportunities.
. On behalf of two West Coast utilities, Dr. Hieronymus testified in a needs certification hearing for a
major coal-fired generation complex concerning the economics of the facility relative to competing
sources of power, particularly unconventional sources and demand reductions.
. For a large western combination utility, he participated in a major 18-month effort to provide the client
with an integrated planning and rate case management system.
. For two Midwestern utilities, Dr. Hieronymus prepared an analysis of intervenor-proposed
modifications to the utilities' resource plans. He then testified on their behalf before a legislative
committee.
U.K. Assignments (1988-1994)
. Following promulgation of the white paper that established the general framework for privatization of
the electricity industry in the United Kingdom, Dr. Hieronymus participated extensively in the task
forces charged with developing the new market system and regulatory regime. His work on behalf of
the Electricity Council and the twelve regional distribution and retail supply companies focused on
the proposed regulatory regime, including the price cap and regulatory formulas, and distribution and
transmission use of system tariffs. He was an active participant in industry-government task forces
charged with creating the legislation, regulatory framework, initial contracts, and rules of the pooling
and settlements system. He also assisted the regional companies in the valuation of initial contract
offers from the generators, including supporting their successful refusal to contract for the proposed
nuclear power plants that subsequently were canceled as being non-commerciaL.
. During the preparation for privatization, Dr. Hieronymus assisted several individual U.K. electricity
companies in understanding the evolving system, in developing use of system tariffs, and in
enhancing commercial capabilties in power purchasing and contracting. He continued to advise a
number of clients, including regional companies, power developers, large industrial customers, and
financial institutions on the U.K. power system for a number of years after privatization.
4
Exhibit No.6
Case No. GNR-E-11-03
W. Hieronymus, IPC
Page 4 of8
Resume of Willam H. Hieronymus
· Dr. Hieronymus assisted four of the regional electricity companies in negotiating equity ownership
positions and developing the power purchase contracts for a 1,825 megawatt combined cycle gas
station. He also assisted clients in evaluating other potential generating investments including
cogeneration and non-conventional resources.
· Dr. Hieronymus also has consulted on the separate reorganization and privatization of the Scottish
electricity sector. Part of his role in that privatization included advising the larger of the two Scottish
companies and, through it, the Secretary of State on all phases of the restructuring and privatization,
including the drafting of regulations, asset valuation, and company strategy.
· He assisted one of the Regional Electricity Companies in England and Wales in the 1993 through
1995 regulatory proceedings that reset the price caps for its retailng and distribution businesses.
Included in this assignment was consideration of such policy issues as incentives for the economic
purchasing of power, the scope of price control, and the use of comparisons among companies as a
basis for price regulation. Dr. Hieronymus's model for determining network refurbishment needs was
used by the regulator in determining revenue allowances for capital investments.
· He assisted one of the Regional Electricity Companies in its defense against a hostile takeover,
including preparation of its submission to the Cabinet Minister who had the responsibility for
determining whether the merger should be referred to the competition authority.
Assignments Outside the U.S. and U.K.
· Dr. Hieronymus testified before the federal court of Australia concerning the market power
implications of acquisition of a share of a large coal-fired generating facility by a large retail and
distribution company.
· Dr. Hieronymus assisted a large state-owned European electricity company in evaluating the impacts
of the EU directive on electricity that inter alia required retail access and competitive markets for
generation. The assignment included advice on the organizational solution to elements of the
directive requiring a separate transmission system operator and the business need to create a
competitive marketing function.
· For the European Bank for Reconstruction and Development, he performed analyses of least-cost
power options and evaluated the return on a major investment that the Bank was considering for a
partially completed nuclear plant in Slovakia. Part of this assignment involved developing a forecast
of electricity prices, both in Eastern Europe and for potential exports to the West.
· For the OECD he performed a study of energy subsidies worldwide and the impact of subsidy
elimination on the environment, particularly on greenhouse gases.
· For the Magyar Vilamos Muvek Troszt, the electricity company of Hungary, Dr. Hieronymus
developed a contract framework to link the operations of the different entities of an electricity sector
in the process of moving from a centralized command- and-control system to a decentralized,
corporatized system.
· For Iberdrola, the largest investor-owned Spanish electricity company, he assisted in development of
their proposal for a fundamental reorganization of the electricity sector, its means of compensating
generation and distribution companies, its regulation, and the phasing out of subsidies. He also has
assisted the company in evaluating generation expansion options and in valuing offers for imported
power.
5
Exhibit No.6
Case No. GNR-E-11-03
W. Hieronymus, IPC
Page 5 of8
Resume of Wiliam H. Hieronymus
. Dr. Hieronymus contributed extensively to a project for the Ukrainian Electricity Ministry, the goal of
which was to reorganize the Ukrainian electricity sector and prepare it for transfer to the private
sector and the attraction of foreign capitaL. The proposed reorganization is based on regional electric
power companies, linked by a unified central market, with market-based prices for electricity.
. At the request of the Ministry of Power of the USSR, Dr. Hieronymus participated in the creation of a
seminar on electricity restructuring and privatization. The seminar was given for 200 invited
Ministerial staff and senior managers for the USSR power system. His specific role was to introduce
the requirements and methods of privatization. Subsequent to the breakup of the Soviet Union, Dr.
Hieronymus continued to advise both the Russian energy and power ministry and the government-
owned generation and transmission company on restructuring and market development issues.
. On behalf of a large continental electricity company, Dr. Hieronymus analyzed the proposed
directives from the European Commission on gas and electricity transit (open access regimes) and
on the internal market for electricity. The purpose of this assignment was to forecast likely
developments in the structure and regulation of the electricity sector in the common market and to
assist the client in understanding their implications.
. For the electric utility company of the Republic of Ireland, he assessed the likely economic benefit of
building an interconnector between Eire and Wales for the sharing of reserves and the interchange
of power.
. For a task force representing the Treasury, electricity generating, and electricity distribution
industries in New Zealand, Dr. Hieronymus undertook an analysis of industry structure and
regulatory alternatives for achieving the economically effcient generation of electricity. The analysis
explored how the industry likely would operate under alternative regimes and their implications for
asset valuation, electricity pricing, competition, and regulatory requirements.
TARIFF DESIGN METHODOLOGIES
AND POLICY ISSUES
. Dr. Hieronymus participated in a series of studies for the National Grid Company of the United
Kingdom and for Scottish Power on appropriate pricing methodologies for transmission, including
incentives for efficient investment and location decisions.
. For a U.S. utility client, he directed an analysis of time-differentiated costs based on accounting
concepts. The study required selection of rating periods and allocation of costs to time periods and
within time periods to rate classes.
. For EPRI, Dr. Hieronymus directed a study that examined the effects of time-of-day rates on the
level and pattern of residential electricity consumption.
. For the EPRI-NARUC Rate Design Study, he developed a methodology for designing optimum cost-
tracking block rate structures.
. On behalf of a group of cogenerators, Dr. Hieronymus filed testimony before the Energy Select
Committee of the UK Parliament on the effects of prices on cogeneration development.
6
Exhibit No.6
Case No. GNR-E-11-03
W. Hieronymus, IPC
Page 6 of8
Resume of Willam H. Hieronymus
· For the Edison Electric Institute (EEl), he prepared a statement of the industry's position on proposed
federal guidelines regarding fuel adjustment clauses. He also assisted EEl in responding to the U.S.
Department of Energy (DOE) guidelines on cost-of-service standards.
· For private utilty clients, Dr. Hieronymus assisted in the preparation both of their comments on draft
FERC regulations and of their compliance plans for PURPA Section 133.
. For a state utilties commission, Dr. Hieronymus assessed its utilities' existing automatic adjustment
clauses to determine their compliance with PURPA and recommended modifications.
· For DOE, he developed an analysis of automatic adjustment clauses currently employed by electric
utilities. The focus of this analysis was on efficiency incentive effects.
· For the commissioners of a public utility commission, Dr. Hieronymus assisted in preparation of
briefing papers, lines of questioning, and proposed findings of fact in a generic rate design
proceeding.
SALES FORECASTING METHODOLOGIES
FOR GAS AND ELECTRIC UTILITIES
· For the White House Sub-Cabinet Task Force on the future of the electric utility industry, Dr.
Hieronymus co-directed a major analysis of "least-cost planning studies" and "low-growth energy
futures." That analysis was the sole demand-side study commissioned by the task force, and it
formed a basis for the task force's conclusions concerning the need for new facilities and the relative
roles of new construction and customer side-of-the-meter programs in utility planning.
· For a large eastern utility, Dr. Hieronymus developed a load forecasting model designed to interface
with the utility's revenue forecasting system-planning functions. The model forecasts detailed
monthly sales and seasonal peaks for a 10-year period.
· For DOE, he directed development of an independent needs assessment model for use by state
public utilty commissions. This major study developed the capabilities required for independent
forecasting by state commissions and provided a forecasting model for their interim use.
· For state regulatory commissions, Dr. Hieronymus has consulted in the development of service area-
level forecasting models of electric utilty companies.
· For EPRI, he authored a study of electricity demand and load forecasting models. The study
surveyed state-of-the-art models of electricity demand and subjected the most promising models to
empirical testing to determine their potential for use in long-term forecasting.
· For a Midwestern electric utility, he provided consulting assistance in improving the client's load
forecast, and testified in defense of the revised forecasting models.
· For an East Coast gas utility, Dr. Hieronymus testified with respect to sales forecasts and provided
consulting assistance in improving the models used to forecast residential and commercial sales.
7
Exhibit No.6
Case No. GNR-E-11-03
W. Hieronymus, IPC
Page 7 of8
Resume of Wiliam H. Hieronymus
OTHER STUDIES PERTAINING TO
REGULATED AND ENERGY COMPANIES
. In a number of antitrust and regulatory matters, Dr. Hieronymus has performed analyses and
litigation support tasks. These cases have included Sherman Act Section 1 and 2 allegations,
contract negotiations, generic rate hearings, ITC hearings, and a major asset valuation suit. In a
major antitrust case, he testified with respect to the demand for business telecommunications
services and the impact of various practices on demand and on the market share of a new entrant.
For a major electrical equipment vendor, Dr. Hieronymus testified on damages with respect to
alleged defects and associated fraud and warranty claims. In connection with mergers for which he
is the market power expert, Dr. Hieronymus assists clients in Hart-Scott-Rodino investigations by the
Antitrust Division of the U.S. Department of Justice and the Federal Trade Commission. In an
arbitration case, he testified as to changed circumstances affecting the equitable nature of a
contract. In a municipalization case, he testified concerning the reasonable expectation period for
the supplier of power and transmission services to a municipality. In two Surface Transportation
Board proceedings, he testified on the suffciency of product market competition to inhibit the
exercise of market power by railroads transporting coal to power plants.
. For one owner of the Trans-Alaskan Pipeline, he submitted testimony to FERC in 2010 concerning
cost pooling and related issues of cost and revenue allocation among co-owner.
. For a landholder, Dr. Hieronymus examined the feasibility and value of an energy conversion project
that sought a long-term lease. The analysis was used in preparing contract negotiation strategies.
. For an industrial client considering development and marketing of a total energy system for
cogeneration of electricity and low-grade heat, Dr. Hieronymus developed an estimate of the
potential market for the system by geographic area.
. For the U.S. Environmental Protection Agency (EPA), he was the principal investigator in a series of
studies that forecasted future supply availabilty and production costs for various grades of steam
and metallurgical coal to be consumed in process heat and utility uses.
Dr. Hieronymus has been an invited speaker at numerous conferences on such issues as market power,
industry restructuring, utility pricing in competitive markets, international developments in utility structure
and regulation, risk analysis for regulated investments, price squeezes, rate design, forecasting customer
response to innovative rates, intervener strategies in utility regulatory proceedings, utilty deregulation,
and utility-related opportunities for investment bankers.
Prior to rejoining CRA in June 2001, Dr. Hieronymus was a Member of the Management Group at PA
Consulting, which acquired Hagler Baily, Inc. in October 2000. He was a Senior Vice President of Hagler
Baily. In 1998, Hagler Baily acquired Dr. Hieronymus's former employer, Putnam, Hayes & Bartlett, Inc.
He was a Managing Director at PHB. He joined PHB in 1978. From 1973 to 1978 he was a Senior
Research Associate and Program Manager for Energy Market Analysis at CRA. Previously, he served as
a project director at Systems Technology Corporation and as an economist while serving as a Captain in
the U.S. Army.
8
Exhibit No.6
Case No. GNR-E-11-03
W. Hieronymus, IPC
Page 8 of8
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 31st day of January 2012 I served a true and
correct copy of the DIRECT TESTIMONY OF WILLIAM H. HIERONYMUS upon the
following named parties by the method indicated below:
Commission Staff
Donald L. Howell, II
Kristine A. Sasser
Deputy Attorneys General
Idaho Public Utilities Commission
472 West Washington (83702)
P.O. Box 83720
Boise, Idaho 83720-0074
Avista Corporation
Michael G. Andrea
Avista Corporation
1411 East Mission Avenue, MSC-23
P.O. Box 3727
Spokane, Washington 99220-3727
PacifiCorp d/b/a Rocky Mountain Power
Daniel E. Solander
PacifiCorp d/b/a Rocky Mountain Power
201 South Main Street, Suite 2300
Salt Lake City, Utah 84111
Kenneth Kaufmann
LOVINGER KAUFMANN, LLP
825 NE Multnomah, Suite 925
Portland, Oregon 97232
Exergy Development, Grand View Solar II,
J.R. Simplot, Northwest and Intermountain
Power Producers Coalition, Board of
Commissioners of Adams County, Idaho,
and Clearwater Paper Corporation
Peter J. Richardson
Gregory M. Adams
RICHARDSON & O'LEARY, PLLC
515 North 27th Street (83702)
P.O. Box 7218
Boise, Idaho 83707
CERTIFICATE OF SERVICE-1
-2 Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email don.howelltCpuc.idaho.gov
kris.sassertCpuc. idaho.gov
Hand Delivered
U.S. Mail
_ Overnight Mail
FAX
-2 Email michael.andrea(Çavistacorp.com
Hand Delivered
U.S. Mail
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Exergy Development Group
James Carkulis, Managing Member
Exergy Development Group of Idaho, LLC
802 West Bannock Street, Suite 1200
Boise, Idaho 83702
Grand View Solar II
Robert A. Paul
Grand View Solar II
15690 Vista Circle
Desert Hot Springs, California 92241
J.R. Simplot Company
Don Sturtevant, Energy Director
J.R. Simplot Company
One Capital Center
999 Main Street
P.O. Box 27
Boise, Idaho 83707-0027
Northwest and Intermountain Power
Producers Coalition
Robert D. Kahn, Executive Director
Northwest and Intermountain Power
Producers Coalition
1117 Minor Avenue, Suite 300
Seattle, Washington 98101
Board of Commissioners of Adams
County, Idaho
Bil Brown, Chair
Board of Commissioners of
Adams County, Idaho
P.O. Box 48
Council, Idaho 83612
Clearwater Paper Corporation
Marv Lewallen
Clearwater Paper Corporation
601 West Riverside Avenue, Suite 1100
Spokane, Washington 99201
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Renewable Energy Coalition
Thomas H. Nelson, Attorney
P.O. Box 1211
Welches, Oregon 97067-1211
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John R. Lowe, Consultant
Renewable Energy Coaliion
12050 SW Tremont Street
Portland, Oregon 97225
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Dynamis Energy, LLC
Ronald L. Willams
WILLIAMS BRADBURY, P.C.
1015 West Hays Street
Boise, Idaho 83702
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Wade Thomas, General Counsel
Dynamis Energy, LLC
776 East Riverside Drive, Suite 150
Eagle, Idaho 83616
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Idaho Windfarms, LLC
Glenn Ikemoto
Margaret Rueger
Idaho Windfarms, LLC
672 Blair Avenue
Piedmont, California 94611
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Interconnect Solar Development, LLC
R. Greg Ferney
MIMURA LAW OFFICES, PLLC
2176 East Franklin Road, Suite 120
Meridian, Idaho 83642
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Bil Piske, Manager
Interconnect Solar Development, LLC
1303 East Carter
Boise, Idaho 83706
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Renewable Northwest Project
Dean J. Miler
McDEVITT & MILLER LLP
420 West Bannock Street (83702)
P.O. Box 2564
Boise, Idaho 83701
Megan Walseth Decker
Senior Staff Counsel
Renewable Northwest Project
917 SW Oak Street, Suite 303
Portland, Oregon 97205
North Side Canal Company and Twin Falls
Canal Company
Shelley M. Davis
BARKER ROSHOLT & SIMPSON, LLP
1010 West Jefferson Street, Suite 102 (83702)
P.O. Box 2139
Boise, Idaho 83701-2139
Brian Olmstead, General Manager
Twin Falls Canal Company
P.O. Box 326
Twin Falls, Idaho 83303
Ted Diehl, General Manager
North Side Canal Company
921 North Lincoln Street
Jerome, Idaho 83338
Birch Power Company
Ted S. Sorenson, P.E.
Birch Power Company
5203 South 11 th East
Idaho Falls, Idaho 83404
Blue Ribbon Energy LLC
M. J. Humphries
Blue Ribbon Energy LLC
4515 South Ammon Road
Ammon, Idaho 83406
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Arron F. Jepson
Blue Ribbon Energy LLC
10660 South 540 East
Sandy, Utah 84070
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Idaho Conservation League
Benjamin J. Otto
Idaho Conservation League
710 North Sixth Street (83702)
P.O. Box 844
Boise, Idaho 83701
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Snake River Allance
Ken Miler
Clean Energy Program Director
Snake River Allance
350 North 9th Street #B610
P.O. Box 1731
Boise, Idaho 83701
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c£y:ø~Donovan E. Walker
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