COM/DGX/tcg Date of Issuance 9/25/2007
Decision 07-09-040 September 20, 2007
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
(See Attachment C for List of Appearances.)
OPINION ON FUTURE POLICY
AND PRICING FOR QUALIFYING FACILITIES
OPINION ON FUTURE POLICY AND PRICING FOR
QUALIFYING FACILITIES 22
3. PURPA and Other Legal Requirements 1313
4. History of SRAC Energy Pricing 2222
4.1. Background of the Formula 2222
4.2. Proposals for SRAC Energy Pricing 2828
5. As-Available Capacity Pricing 7575
7. Policy Proposals for QFs with Expiring Contracts and New QFs 100100
8. The Record is Sufficient Despite Confidentiality Concerns 136136
11. Assignment of Proceeding 140140
LIST OF TABLES
Table 1 - Qualifying Facility (QF) Programs - Adopted and Existing
Table 2 - Party Positions on SRAC Energy Pricing
Table 3 - Sample Derivation of IER (SP15)
Table 4 - Adopted SRAC Energy Pricing
Table 4a - All-in Power Prices - Adopted Energy and Capacity Pricing at
an Illustrative Gas Price
Table 5 - QF Capacity Payments
Table 6 - Power Contract Components
Table 7 - QF LRAC Proposals and All-In Payments
LIST OF ATTACHMENTS
Attachment A - Summary of Standard Offer Contracts for Qualifying Facilities
Attachment B - List of Acronyms and Abbreviations
Attachment C - List of Appearances
OPINION ON FUTURE POLICY
AND PRICING FOR QUALIFYING FACILITIES
1. Summary
In this order, we adopt specific policies and pricing mechanisms applicable to the electric utilities' purchase of energy and capacity from qualifying facilities (QFs) pursuant to the Public Utilities Regulatory Policy Act of 1978 (PURPA).1
Specifically, we adopt:
· The Market Index Formula (MIF), which is an updated short-run avoided cost (SRAC) formula for pricing SRAC energy. The MIF is based on the Decision (D.) 01-03-067 Modified Transition Formula but contains both a market-based heat rate component, and an administratively determined heat rate component to calculate the incremental energy rate (IER);
· Two Standard Contract Options for Expiring or Expired QF Contracts and New QFs:
o One- to Five-Year As-Available Power Contract.
o One- to Ten-Year Firm, Unit-Contingent Power Contract.
o QFs will also continue to have the option of either participating in Investor-Owned Utilities (IOU) power solicitations, or negotiating bilateral contracts with the IOUs.
· Prospective QF Program Contract Provisions
o Short Term (1-5 years) As-Available Contracts:
_ SRAC Energy Payments: MIF. Existing QF contracts providing SRAC energy will also be priced pursuant to the MIF.
_ Payments for As-Available Capacity: Based on the fixed cost of a Combustion Turbine (CT) as proposed by The Utility Reform Network (TURN), less the estimated value of Ancillary Services (A/S) as proposed by San Diego Gas & Electric Company (SDG&E) and capacity value that is recovered in market energy prices as proposed by TURN and SDG&E.
o Longer Term (1-10 Years) Firm, Unit Contingent Contracts:
_ Energy Payments: MIF.
_ Capacity Payment for Firm: Based on the market price referent (MPR) capacity cost adopted in Resolution E-4049, less the value of energy-related capital costs (or inframarginal rents) as proposed by SCE.
o The EEI contract2 will be the basis for our Prospective QF Program contract options, however, a simplified version of the EEI contract shall be utilized for Small QFs.
o The first two adopted Prospective QF Program contract options are available to QFs with existing contracts, as well as QFs that are, or were, on contract extensions set forth in D.02-08-071, D.03-12-062, D.04-01-050, and D.05-12-009.
o Subject to the special provisions described below for small QFs, IOU may only deny a prospective contract if it will result in over-subscription and after it meets and confers with its Procurement Review Group (PRG). IOUs will not be required to purchase QF capacity if the utility can demonstrate that it does not need the capacity.
_ Notwithstanding the above, IOUs may not deny either of the 2 contract options to small QFs for any reason related to oversubscription unless the total capacity of QF power would, with the proposed contract, exceed 110% of the utilities QF capacity as of the date of this decision. Small QFs are defined as QFs under 20 MW or that offer equivalent annual energy deliveries of 131,400 MWh and that consume at least 25% of the power internally and sell 100% of the surplus to the utilities.
Additional provisions are outlined in Table 1.
1.1. Recent Developments and
Scope of this Order
Two recent developments limit the effect of this order on energy prices and capacity prices over the next five years because (1) a large number of QFs have entered into contractually based energy pricing agreements, and (2) many existing QFs are on contractually based capacity pricing. In addition, we anticipate that the Market Redesign and Technology Update (MRTU) will be operational within the next 12 months and will provide a robustly traded day-ahead market that establishes a market price that reflects the full avoided costs of the state's utilities.
With regard to energy, in D.06-07-032, we adopted the Pacific Gas and Electric Company (PG&E)/Independent Energy Producers (IEP) Settlement Agreement, in which 121 power projects entered into either a fixed or variable energy price agreement with PG&E. The power deliveries associated with the PG&E/IEP Settlement Agreement "represent almost 52.04% of generation deliveries from all QFs currently under contract with PG&E" (D.06-07-032, pp. 4-5). On October 19, 2006, in Resolution E-4026, we approved Southern California Edison Company's (SCE) request for approval of 61 fixed price energy agreements with existing renewable QFs for a five-year period commencing on May 1, 2007, and ending on April 30, 2012. The 61 contracts represent 1,840 MW of May 2006 on-line capacity for SCE. With regard to capacity payments, many QFs are on contractually-based capacity pricing. Thus, our determination here on updated as-available capacity prices will have a limited impact on the utilities and on the entire pool of QFs.
Since the early 1980s, this Commission's goal in implementing PURPA has been to encourage the development of cost-effective alternative and renewable generation3, while protecting California's utility ratepayers by ensuring that utilities pay rates that do not exceed what they would have incurred but for purchasing QF power. Today's decision is consistent with this goal, but reflects the fact that the electricity procurement market has changed significantly since the initial standard offer contracts were approved by this Commission.
PURPA requires that QFs be compensated for power deliveries at a level equal to, but not higher than, "the incremental costs to an electric utility of electric energy or capacity or both, which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source."4 Thus a primary goal and guidepost in this proceeding is the need to determine the most reasonable estimate of the costs a utility would incur to obtain an amount of power that it purchases from a QF, either by the utility's self-generation or by purchase from a third party, on a short-term and long-term basis.
In addition to evaluating which QF policy approach is the best fit for California at this time, we must consider which proposals are consistent with state and federal law. Today's decision provides utilities and QFs with two flexible contracting options that reflect the requirements of PURPA and the realities of California's energy markets. The policies adopted are consistent with and implement federal and state law regarding QFs, and existing Commission decisions as well as the policy goals articulated in our Energy Action Plan (EAP II). In the EAP we adopted "a long-term policy for existing and new qualifying facility resources, including better integration of these resources into California Independent System Operator (CAISO) tariffs and deliverability standards" (EAP II, Section 4 and 7).5
With respect to the short-run avoided cost of energy, or SRAC, we have been presented with proposals that range from shifting SRAC directly to market prices, modifying the current formula to link SRAC to market prices, or retaining the current formula. While solely using power market prices to determine SRAC sounds simple and appealing, it would require legislation to eliminate Pub. Util. Code § 390(b), which requires SRAC to be tied to natural gas prices. However, revising the Transition Formulas adopted in D.96-12-028, as modified by D.01-03-067 will not require statutory changes and will permit us to tie SRAC to market prices, and still comply with Section 390(b).
Accordingly for PG&E, SCE, and SDG&E, we define and adopt the Market Index Formula or "MIF" to calculate SRAC energy payments to QFs. The MIF equation is similar to the Modified Transition Formula we adopted for SCE in D.01-03-067, with the exception that the heat rate component, formerly the Incremental Energy Rate (IER), will be calculated using an average of a market derived heat rate and the existing administratively set heat rates. The market-based component will be calculated using a 12 month rolling average of forward market prices. The forward market prices will be based on a weighted average price6 of the forward market prices for North of Path 15 (NP15) or South of Path 15 (SP15), as reported in Platts Megawatt Daily and/or the Intercontinental Exchange (ICE)7.
For long-term QF policies, we have been presented with several proposals from the investor-owned utilities (IOUs) and consumer advocacy groups that would allow QFs to compete in utility resource solicitations, with their price based on the competitive bidding process and provide a one-year market-based contract for QFs who are either unwilling or unable to participate in IOU solicitations.
We have also been presented with proposals from the QF community requesting that the Commission reinstate a series of long term (10 to 20-year) standard offers available to all QFs with expiring contracts as well as new QFs, at prices based on the estimated cost of a combined cycle generating plant. As we discuss below, our experiences with long-term QF contracts have left us unwilling to exactly replicate past practices. Instead, after extensive review, we conclude that the QF procurement process should include power product differentiation and increased flexible performance requirements to better reflect the fact that competition to serve new demand in California exists among utilities, QFs and other non-utility independent power producers. This reality, and the resulting market pricing mechanisms it offers, suggests that QFs should be given reasonable options and incentives to compete with other power providers.
However, we are persuaded that there are currently few options to utility purchases, particularly for Small QFs, whose size prevents them from participation in the CAISO markets.8 These QF should continue to have available standard offers, albeit at market prices.
For these reasons, we adopt flexible market-based contract options in addition to the competitive solicitation and bilateral contracting options already available to QFs. First, QFs who choose only to provide non-firm, as-available power will have access to a one- to five-year as-available contract with energy prices based on the MIF formula and posted as-available capacity payments based on the cost of a combustion turbine less the estimated value of Ancillary Services and the capacity value that is recovered in market energy prices.
Second, we will make available a one-to-ten-year contract for firm unit-contingent power, with energy prices based on the MIF and capacity payments based on the MPR capacity cost in Resolution E-4049, less the value of energy-related capital costs. This longer-term contract option is intended to provide sufficient contract and pricing certainty to allow QFs to make decisions on capital expenditures for facilities and upgrades. We also adopt contracting protections for Small QFs.
Our prior PURPA implementation policies reflected a time when the QF industry was in its infancy, and standard offers were deemed the fastest, most efficient way to spur new technology and investment. However, this is no longer a nascent industry. QF generation is currently well established and constitutes 20-30% of the utilities' resource portfolios.
We also recognize that utilities are reluctant to keep QFs in their portfolios because they do not contain the performance guarantees that utilities would otherwise need to include in power contracts and that are commonly available in the market. For example, the frequently touted benefits that QFs offer the state, (i.e., that they are in or near utility load centers or load pockets, utilize existing interconnections and transmission access, facilitate peak power deliveries, and provide environmental benefits) may not be characteristic of all QFs. However, QFs which are able to offer these benefits should be uniquely situated to compete in utility solicitations at prices that reflect the cost that the utilities would otherwise have to pay for an equivalent resource, consistent with PURPA.
The contract terms and pricing in this decision apply specifically to expired, expiring and new QF contracts. Other than updating the SRAC formula and posted capacity prices, we do not change existing QF contracts. Furthermore, this decision updates the methodology for calculating SRAC energy prices on a prospective basis only, to ensure that SRAC prices continue to reflect utility avoided cost in the changing electricity markets in California. In comments, SCE has requested that the adopted MIF be applied retroactively. However, updating the SRAC formula to better reflect changes in the energy market does not, by itself, indicate that SRAC prices under the prior formula were in violation of PURPA. Furthermore, the record in this proceeding does not support a conclusion that the Modified Formula yielded prices that exceed utility avoided costs or systematically violated PURPA.
We also continue to require the utilities to make available CAISO scheduling services to QFs. QFs whose size prevents them from participation in the CAISO markets should not have to establish scheduling operations staff to interact with the CAISO.
1 The United States Congress passed PURPA in 1978, as codified in the United States Codes (USC) at 16 U.S.C. § 824a-3, and 18 Code Federal Regulations (CFR) §§ 292.301 et seq.
2 Electric Edison Institute (EEI) contract, http://www.eei.org/industry_issues/legal_and_business_practices/master_contract/OptionalProvisions.htm
3 "One of PURPA's stated goals is to encourage the development of alternative and renewable generation of electricity in the United States. To serve this end, PURPA sets forth two major provisions. First, PURPA requires utilities to interconnect with and purchase power from QFs at prices up to a utility's avoided cost. Second, PURPA exempts QFs from standard utility cost-of-service regulation." (D.01-05-085, mimeo., p. 2.)
4 18 CFR § 292.101(b)(6).
5 EAP II was adopted by this Commission in October 2005 and is a joint policy plan by the California Public Utilities Commission (CPUC) and the California Energy Commission.
6 The monthly weighted average power price is determined as follows. The monthly peak power price is weighted 57% and the off-peak power price is weighted 43%, where the peak weighting factor of 57% is equal to (6x16)÷(24x7), and the off-peak factor of 43% is equal to 1 minus 57%. For example, $75/MWh peak times 57%, plus $40/MWh off-peak times 43% equals $60/MWh.
8 Generators may not participate in CAISO markets, including the upcoming Market Redesign and Technology Upgrade (MRTU) market, unless the generator is capable of providing at least one MW of dependable capacity.
