IV. Should the Commission Reinstitute Standard Offer 1 Contracts and Adopt a Right of First Refusal for Qualifying Facilities?

CCC calls upon the Commission to once again require utilities to make Standard Offer 1 contracts (SO1) available to QFs with a design capacity greater than 100 kilowatts (kW). CCC additionally asserts that QFs are entitled to a "right of first refusal" (ROFR) with respect to all energy and/or capacity contracts that investor-owned utilities (IOUs) might enter into with non-QF suppliers.

A. The Statutory and Regulatory Framework Governing PURPA

1. Federal Law

The Public Utility Regulatory Policy Act of 1978 (PURPA), as codified in the United States Codes (USC) at 16 U.S.C. § 824a-3, requires the Federal Energy Regulatory Commission (FERC) to prescribe and periodically revise rules that "require electric utilities to offer to . . . (2) purchase electric energy from [QFs]."²⁹ Rates paid by utilities for purchases of electric energy may not exceed "the incremental cost to the electric utility of alternative electric energy."³⁰ PURPA defines incremental cost with respect to electric energy purchased from a QF as "the cost to the electric utility of the electric energy which, but for the purchases from such [QF] such utility would generate or purchase from another source."³¹

The FERC has complied with its PURPA obligation to "prescribe rules" by promulgating in the Code of Federal Regulations (CFR) 18 CFR § 292 et seq. The rules set forth therein provide in pertinent part that: "each electric utility shall purchase, in accordance with [18 CFR] § 292.304, any energy and capacity which is made available from a [QF]. . . "³² §292.304, entitled "rates for purchases," establishes a pricing regime for purchases by IOUs from QFs. Consistent with 18 U.S.C. § 824a-3, § 292.304(a)(1) requires first that "rates for purchases shall: (i) [b]e just and reasonable to the electric consumer of the electric utility and in the public interest. . ."³³ While rates may not exceed avoided costs,³⁴ rates will satisfy the "just and reasonable" and non-discrimination requirements of § 292.304(a) "if the rate equals the avoided costs determined after consideration of the factors set forth in paragraph (e) of this section."³⁵ Paragraph (e) provides a laundry list of factors to be taken into account in determining avoided costs, "to the extent practicable." These are elaborated upon below.

The FERC's rules require that standard rates for purchases be put into effect only "for purchases from qualifying facilities with a design capacity of 100 kilowatts or less."³⁶ Whether to implement standard rates for qualifying facilities "with a design capacity of more than 100 kilowatts" is discretionary.³⁷

Purchases from "as-available" QFs are subject to special pricing rules. QFs may provide energy as it is available, "in which case the rates for such purchases shall be based on the purchasing utility's avoided costs calculated at the time of delivery."³⁸ QFs providing electric energy or capacity under a contract are to be paid either avoided costs at the time of delivery, or avoided costs calculated at the time the QF entered the contract, whichever the QF chooses at the time it enters the contract.³⁹

2. State Law

PURPA also imposed an obligation on this Commission. "[E]ach State regulatory authority shall . . . implement [the FERC QF rules] for each electric utility for which it has ratemaking authority."⁴⁰ It falls to this Commission to implement the pricing provisions just elaborated. This Commission has a lengthy history of setting QF prices, which we need not elaborate here. For present purposes, it is sufficient to pick up the story with the Commission's D.96-10-036, which significantly revamped our handling of QF pricing, and which is central to any analysis of CCC's proposals. We will touch on the particulars of D.96-10-036 as it applies to CCC's proposals in more detail below, but will briefly summarize the decision here. In D.96-10-036, the Commission undertook to bring its QF implementation practices into the restructured world. Of particular significance to the issues in this docket, the Commission terminated as of January 1, 1998 any requirement that utilities enter SO1 or SO3 contracts with QFs. "QFs with design capacity 100 kW or less may negotiate non-standard agreements based upon the standard rates applicable to grand fathered USO1's and tariff Rule 21."⁴¹

The Commission further provided that "utilities shall not recover in rates any portion of payments to as-available QFs holding non-standard agreements entered into after December 20, 1995, that, at the time of delivery, are greater than market prices."⁴² The Commission explicitly migrated QFs towards full and equal participation in markets alongside other sources of generation, stating:

We therefore place QFs, with two limited exceptions, on notice that they cannot rely upon obtaining regulatory must-take status if the date of formation of their agreement with PG&E, Edison, or SDG&E is after December 20, 1995. No modification of our Restructuring Decision is involved: the plain meaning of "grand fathered" is consistent with this result. New QFs will be, as soon as the restructured market begins operation, "subject to the same protocols and prices regarding transmission access and treatment of transmission congestion." They will clear the power exchange if they bid low enough relative to all other sources to clear the market.⁴³

For "grandfathered" QFs, i.e., those with contracts entered prior to December 20, 1995, pricing would continue to be based on the contract terms, which almost universally set price at "short run avoided cost." (SRAC.) With respect to SRAC, the legislature took a hand when it enacted Public Utilities Code Section 390 as part of AB 1890. Generally speaking, Public Utilities Code Section 390 sets out components (most significantly, gas costs) to use in setting SRAC, pending a shift to the use of PX prices to establish SRAC. The Commission implemented R.99-11-022 to work out the particulars of SRAC pricing under Public Utilities Code Section 390. Events overtook this rulemaking, and the demise of the PX in January 2001 ended any chance of a universal migration of QFs to PX-based SRAC pricing. At present, SRAC is set using a formula based on gas prices.⁴⁴ Each utility has detailed QF pricing information (current and historical) on its respective website.⁴⁵

B. Analysis of the CCC Proposals

1. The Proposal to Require IOUs to Offer SO1 Contracts to QFs With a Design Capacity of More Than 100 Kilowatts

In D.96-10-036, the Commission decided that IOUs need no longer make SO contracts available to QFs with a design capacity of more than 100 kW after January 1, 1998.⁴⁶ Whether to require that IOUs' offer QFs SO contracts is entirely within the Commission's discretion.⁴⁷ Indeed, even whether to set standard rates is discretionary with the Commission for facilities with a design capacity of more than 100 kW. ⁴⁸

Much has changed since this Commission issued D.96-10-036. But if circumstances have changed since the issuance of D.96-10-036, they have changed even more greatly since this Commission originally promulgated the SO1 contract. As we explained in D.96-10-036, the SO contracts were introduced in 1982:

when the Commission had an overarching policy objective of encouraging QF development, no excess capacity forecasts, no stranded costs to consider, no rate cap, no broadly available transmission access to facilitate other competitive generation sources, and other wholesale purchase activities of utilities were, by today's standards, relatively shallow and uninformative.⁴⁹

We are not persuaded on the record before us, in the context of this motion for interim relief, to overturn D.96-10-036 and re-institute the utility obligation to enter SO contracts. In implementing PURPA today, we are no longer jump-starting a nascent industry, as we were in 1982. Every aspect of the SO1 contract deserves scrutiny, beyond what has occurred in the context of CCC's proposal here. CCC dismisses the contentions of SDG&E witness Farrelly that the SO1 contract is out of date,⁵⁰ but we think the question of how well SO contracts conform to today's energy industry bears further examination. SCE witness Bergmann's assertion that the SO4 contract could form a basis for new contracts may well prove correct,⁵¹ but this claim does not lend credence to the argument that the Commission should simply reinstitute a 20-year old contract without a detailed re-examination of that contract's terms.

CCC's proposal has not received the unanimous support of the QF industry, and that in fact it is only co-generators (and not the broader community of QF generators, including renewables) pressing for the return of the SO1 contract. Not one of the renewable resource parties that filed a brief concerning SCE's motion⁵² endorses CCC's proposal to reinstitute the requirement that utilities make available SO1 contracts.⁵³

We note a host of problems with the arguments underpinning CCC's proposal. CCC asserts that prices under SRAC have been within "1% of the average spot market energy price," save for during the 2000-2001 crisis, when SRAC prices were below market prices.⁵⁴ However, the Beach testimony upon which CCC relies for its assertion regarding comparability does not make an apples-to-apples comparison between energy prices in markets (which include capacity payments in the energy price) and SRAC prices (which do not include capacity payments in the energy price). QFs receiving SRAC payments also received separate, additional, capacity payments, a fact not reflected in Mr. Beach's testimony. In addition, SRAC prices would be available at any time, even off-peak when well in excess of prevailing market prices. CCC's contention that excess power taken under QF contracts could be sold "in the market [at] a price that is comparable to the SRAC price paid to the QFs"⁵⁵ strikes us as wishful thinking. We are all too cognizant of the difficulties DWR is having disposing of excess power under its long-term power purchase agreements. Were it as simple as CCC would have us believe to economically dispose of excess power, CCC would not be making its proposal.

On a related note, PG&E complains that entering into additional SO1 contracts will complicate, or at the least fail to simplify, PG&E's procurement responsibility.⁵⁶ PG&E also observes that the proposal is "without limitation as to transitional procurement versus long-term." We observe that the longest duration agreement proposed by SCE would be for five years. SO1 contracts originally had a term "not to exceed 30 years," later shortened to six years, with the possibility of one year extensions thereafter.⁵⁷

We deny here, in the narrow confines of SCE's motion for interim procurement authority, CCC's proposal to once again require utilities to enter SO1 contracts with QFs. Such issues are best addressed elsewhere on a less-expedited time frame and in the context of a fuller reexamination of our QF policies. In the meantime, CCC members remain free to pursue non-standard contract opportunities, as elaborated upon below.

2. The Proposal to Provide QFs With an ROFR

At the outset we must confess to some uncertainty regarding whether CCC proposes an ROFR for any QF, or just for QFs with energy not already encumbered by any SO contracts with IOUs. The proposal does not appear to distinguish between QF capacity or energy that is encumbered or unencumbered by SO contracts. A QF with capacity or energy encumbered by an SO contract is already required to make capacity and energy available under the terms SO contract, and so would not seem to have anything to offer other than energy not subject to the SO contract. Accordingly, we interpret CCC's proposal as limiting the ROFR to QFs with capacity or energy unencumbered by any SO contract with an IOU to the extent of the unencumbered energy.⁵⁸

We reject the fundamental premise of CCC's claim to an ROFR - that the interim procurement process establishes avoided cost for purposes of implementing PURPA. The FERC's regulations⁵⁹ identify numerous factors that "shall, to the extent practicable, be taken into account" in determining avoided costs. These factors include data on utility generation construction costs,⁶⁰ the operating characteristics of a particular QF, including dispatchability, reliability, and usefulness during emergency, value of products from other QFs, and the relative ease with which QF capacity can be added to the grid,⁶¹ reductions in fossil fuel use,⁶² and reductions in line losses. In addition, we are constrained by Public Utilities Code Section 390 to calculate avoided costs "paid to nonutility power generators . . . based upon the commission's prescribed `short run avoided cost energy methodology' . . . as set forth in [Public Utilities Code Section 390] subdivisions (b) and (c)." Subdivision (b) ties short run avoided cost energy payments to a gas index price, while Subdivision (c) ties short run avoided costs to "the clearing price paid by the independent Power Exchange," subject to the occurrence of certain conditions precedent.⁶³ What SRAC should be under Public Utilities Code Section 390 was the subject of a lengthy proceeding in R.99-11-022. CCC was deeply enmeshed in R.99-11-022, having sought rehearing of numerous commission decisions in that proceeding.⁶⁴ This Commission never determined that the PX was functioning properly, and it is now defunct. Accordingly, this Commission has never endorsed a shift to market prices for determining avoided costs.

Neither PURPA itself nor the FERC regulations implementing PURPA expressly grant an ROFR to QFs. CCC would have us find one implicit in the regulatory framework elaborated above. Presumably if PURPA contained an implicit grant we would find numerous occasions on which QFs were pushed to the "head of the line" ahead of other procurement options, but we find no particular examples outside of the Biennial Resource Plan Update (BRPU) process, about which more later.⁶⁵ As PG&E points out in its brief, QFs were not pushed to the "head of the line" in the PX auction. Nor, we note, are QFs pushed to the head of the line in auctions in the ISO markets for energy or Ancillary Services.

PG&E brings up the FERC's order rejecting the BRPU process.⁶⁶ PG&E apparently reads that order as mandating a single, single-price auction, presumably in reliance on the statement that: "[t]he [FERC] reasoned that sections 210(b) and 210(d) of PURPA require that any determination of avoided cost must take into account all potential sources of capacity, and that the California program improperly limited itself to only certain sellers (QFs)."⁶⁷

The principal faults allegedly suffered by the BRPU process were:

[a]s explained in the February 23 order and as explained further below, [that] the ultimate method of determining price for California QF power was in the auction process following administrative determination of the IDR⁶⁸ benchmarks. The auction process did not include all sources of power and, as Edison and San Diego continue to explain in their answers to the requests for reconsideration, did not allow for the selection of the lowest cost bidders."⁶⁹

Moreover:

The benchmark considered only the purchasing utility's cost of generating energy but did not take into account fully what it would cost to purchase such energy from another source, as required by PURPA's definition of avoided (incremental) cost. While the benchmark process may have taken all technological sources into account, it did not consider all types of sellers (QFs, IPPs, IOUs, etc.).⁷⁰

What CCC is proposing here is not the "QF only" auction that the FERC rejected in connection with this Commission's BRPU proceeding. Significantly, in contrast to the BRPU process' "QF only" auction, the proposal here would take account of "all generation resources"⁷¹ by moving QFs to the "head of the line" at the conclusion rather than outset of the procurement process. This simple but significant distinction makes the Southern California decision inapplicable by ensuring that all resources' bids are taken into account in the ultimate method of determining a price for QFs.

There is, however, another aspect of the Southern California decision that merits further discussion. In Southern California, the FERC noted that:

[t]he California utilities have claimed, with considerable validity, that in order to demonstrate that a non-QF purchase option was indeed available, it would be necessary to negotiate with potential non-QF sellers as to price and terms, and that non-QF suppliers would not, in reality, negotiate seriously if the resulting "sale" would simply result in a benchmark price to be used as a target for QF bidders.⁷²

The argument made by the IOUs in Southern California, and endorsed by the FERC (as noted with italics) resurfaces here. As CCC notes in its brief, "Edison and SDG&E also objected that potential non-QF bidders might be reluctant to bid for a product if they knew another party had a ROFR."⁷³ CCC makes light of this objection, dismissing it as speculative,⁷⁴ and asserting that the threat of exercise of an ROFR will drive prices down.⁷⁵ We are not so sanguine. PG&E argues that:

Few things would be as disruptive of an orderly and efficient RFO process as the "right of first refusal" contended for by CCC. California Wind Energy Association, which includes QFs among its members, points out that: `Non-QFs might hesitate to bid if they believed their bids, if initially successful, would become mere targets for matching by non-selected QFs with a right of first refusal. Also, if non-QFs hesitate to bid, the competition will be less vigorous and the prices less favorable to consumers.'⁷⁶

This leads to a related concern - the fundability of suppliers. A wind generator is not necessarily substitutable for a combustion turbine. A steam host is not necessarily substitutable for a base-load plant. We are concerned about the possibility of mismatching contracts with providers if QFs generically are allowed to step into agreements negotiated with other parties. We will address these concerns in more detail in our decision resolving the balance of this case.

QFs will, like all market participants, have a chance to sell to IOUs through the interim procurement process. If a QF makes a "winning" bid (i.e., a bid conforming to the technical requirements of the RFP that is at or below the highest accepted bid) to an IOU, the IOU must accept the bid. If a QF has mis-gauged its bid, PURPA does not entitle the QF to another bite at the apple. CCC seeks to anticipate arguments that its proposal invites QF gaming of the auction process by clarifying that its proposal is for QFs to either bid, or exercise an ROFR, but not both in connection with a given procurement process. While this either/or approach might reduce gaming opportunities available to QFs were the ROFR adopted, it does not address the fact that members of a single class of bidders are free, at their discretion, to swoop down and snag for themselves the entirety or portions of the most attractive contracts at the last minute. This would seem to be just as likely to "lead to chaos in these solicitations"⁷⁷ as allowing a winning bidder to engage in a second round of bidding against a QF exercising its ROFR.

Anticipating the foregoing line of reasoning, CCC contends that "the Commission should appreciate that simply allowing QFs to participate in a first price auction, or other procurement forum in which prospective sellers receive their bid price if selected, would not satisfy PURPA's avoided cost requirements."⁷⁸ In rebuttal, ORA states that "ORA agrees with SCE's position that `[t]he Commission has dealt with that issue by suspending standard offers, and instead suggesting that the market is the alternative means by which you satisfy the mandatory purchase obligation" (Bergmann, Edison, Tr. p. 442).'"

We agree with Edison and ORA that the market might be an alternative means by which the Commission can satisfy PURPA's dictates. In D.96-10-036 we expressed our expectation that eventually all QFs would be paid and scheduled through the PX, which was expected to set prices and select sellers through a single price auction. Allowing QFs to participate in a first price auction - albeit an auction run by the IOUs rather than by the now-defunct PX - can satisfy PURPA's must-take and avoided cost pricing requirements. We never, however, approved a switch over to PX pricing for establishing avoided costs, and we are unready to conclude today that we have reached a point where a market provides a proper benchmark for establishing avoided costs. We will continue to rely on our administrative processes to set avoided cost prices for purchases pursuant to PURPA.