# Appendix — Pacific Gas & Electric Co. v. Public Utilities Commission > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385019_0699%3A2 ## Record - **Collection:** Supreme Court brief - **Document type:** Appendix - **Published:** January 1, 1987 - **Citation:** 484 U.S. 853 ## Text Supreme Court, U.S. rit E ® 87-178 JUL 281987 No. JOSEPH F. SPANIOL, JR. Fae BRK In the Supreme Court OF THE United States OCTOBER TERM, 1987 PaciFic GAS AND ELECTRIC COMPANY, a California Corporation Petitioner, V. PusBLic UTILITIES COMMISSION OF THE STATE OF CALIFORNIA, Respondent. APPENDIX TO PETITION FOR WRIT OF CERTIORARI TO THE CALIFORNIA SUPREME COURT HOWARD V. GOLUB ROBERT L. HARRIS *LINDA L. AGERTER P.O. Box 7442 77 Beale Street San Francisco, California 94120 (415) 781-4211 *Counsel of Record for Petitioner Pacific Gas and Electric Company BOWNE OF SAN FRANCISCO. INC. + 190 NINTH ST. « S.F.. CA 94103 + (415) 864-2300 anal > ne-zosmooe> ff zie TABLE OF CONTENTS Title Pages Order Denying Alternative Writ ................cccecee. A-1 Ne ca cead tence weaduenadeatns A-2 se bbl ances an behead een eee A-50 ME occ ccccdseasascdausbeiewsenues A-56 Ee rind cnacesccanctuantdwes sents A-61 IID oan 6d one 540e0eKs ousensvecveaten A-126 I Gy cabs utdubrensvsiwssdanwer A-141 Ps ca cedcadekekbewessxtves es A-145 Decision No. 86-12-104 Certification of Mailing .......... A-149 Application for Rehearing of Decision No. 86-10-038 ...... A-168 Pacific Gas and Electric Co. Standard Offer No. 4—Power ee ccc bou ns dkenek hanes sake ees A-186 I ED ic ks crea cusesusecvsnsstvane A-247 PURPA, Section 210, 16 U.S.C. § 824a-3................ A-257 Analysis of Assembly Bills 1402 and 1403................ A-263 Sia ee ee rn he rv Pas UJ “ay a wet A-l APPENDIX A Order Denying Alternative Writ S.F. No. 25114 In the Supreme Court of the State of California In Bank Pacific Gas and Electric, Petitioner v. Public Utilities Commission, Respondent. Panelli, J., Did Not Participate [ Filed April 30, 1987] Petition for Writ of Review DENIED. /s/ Lucas Chief Justice A-2 APPENDIX B Decision 83-09-054 September 7, 1983 BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA Application 82-04-44 (Filed April 21, 1982; amended April 28, 1982, July 19, 1982, July 11, 1983 and August 2, 1983) Second Application of PACIFIC GAS AND ELECTRIC COMPANY for Approval of Certain Standard Offers Pursuant to Decision No. 82-01-103 in Order Instituting Rulemaking No. 2. Application 82-04-46 (Filed April 21, 1982; amended May 12, 1982; July 11, 1983 and August 10, 1983) In the Matter of the Application of SOUTHERN CALIFOR- NIA EDISON COMPANY for an Order by the California Public Utilities Commission Directing Edison to Purchase Power from Qualifying Facilities Based on a Standard Offer for Firm Capacity and Energy Based on Long-Run Marginal Costs (OIR-2). Application 82-04-47 (Filed April 21, 1982; amended July 11, 1983, and August 2, 1983) In the Matter of the Application of SAN DIEGO GAS & ELECTRIC COMPANY for an Order by the California Public Utilities Commission Directing SDG&E to Purchase Power from Qualifying Facilities Based on Standard Offers and to Make Certain Changes or Additions to its Tariffs Affecting Purchases from Qualifying Facilities. (For appearances see Appendix A.) A-3 INTERIM OPINION These proceedings involve adopting standard offers based on long-run avoided costs for power purchase contracts between the three largest electric utilities and qualifying facilities (QF). The utilities are: Pacific Gas and Electric Company (PG&E), South- ern California Edison Company (SCE), and San Diego Gas and Electric Company (SDG&E). Before explaining the procedural history which has brought us to this point, we think it is constructive to explain briefly why we have pursued developing such standard offers in view of the standard offers in-place which pay QFs for their power based on actual short-run utility avoided costs. I. SUMMARY OF DECISION This decision authorizes what is termed Standard Offer #4, which has different payment options for QFs, all of which are based on forecasts of the utilities’ resource mix and costs. The three payment options under Standard Offer #4 resulted from negotiations. A negotiating conference, which lasted five weeks, was held at our direction, with vigorous participation by utilities, QFs, and our staff. We have committed to hold evidentiary hearings, which almost all parties desire. However, there is substantial agreement among utilities, QFs, and our staff that until a more permanent solution is found for the complex task of fairly valuing and pricing QF power over the long-run, Standard Offer #4, with three payment options, should go into effect. We undertook the negotiating conference in the hope of com- ing closer to an interim solution which, while not perfect from all perspectives, could be useful for QFs and utilities. While some may have hoped to accomplish more than the scope of the consensus reached, or they would have preferred different results, we think the negotiating conference was extremely fruitful. The negotiated standard offer and three payment options are approved, with some reasonable restrictions on their use set by us under our prerogative. A-4 Standard Offer #4, at this juncture, is interim in the sense it may ultimately be replaced with a different costing methodology, contract terms, etc. However, until that happens, it may be fully relied on by utilities and QFs who find the options useful. Those who contract under interim Standard Offer #4 will not be subject to having terms or prices changed later, except as narrowly and specifically ordered by this decision. Any changes made to this standard offer in the future will only apply to those contracting after such changes. Potential QFs who find they cannot use Standard Offer #4, as approved today, still have the option of pursuing a negotiated nonstandard contract with utilities. Il. BACKGROUND Utilities’ short-run avoided costs have proven to be more volatile than many observers would have guessed. We have seen a drastic run-up in fuel oil and gas prices, followed by a moderate decline in oil prices. The QF industry contends that the price uncertainty posed under the existing as-available and firm capac- ity standard offers, both based on short-run avoided costs, makes it extremely difficult to arrange financing for potential QF projects. QFs tell us that those who hold the financing purse- strings, both lenders and equity investors, are reluctant to commit captial when a project’s payment stream is so uncertain. Our Decision (D.) 82-01-103 in OIR 2, issued January 21, 1982, recognized the need to pursue developing standard offers based on long-run avoided utility costs (page 67, mimeo.). Oil and gas prices were steadily rising when that decision was issued, and although the three largest electric utilities were ordered to file applications with proposed standard offers based on long-run avoided costs, most of our attention and that of the QF industry was directed to perfecting standard offers based on short-run avoided costs. Many assumed oil prices would continue to rise; few seemed to believe they would start a decline. As oil prices started to decline the intensity of interest in standard offers which would produce prices based on long-run (and presumably less volatile) avoided costs correspondingly increased. If we do not adopt a standard offer based on long-run avoided costs as an alternative to the existing standard offers, the pressure A-5 for nonstandard contracts between utilities and QFs could steadily increase. Such nonstandard contract negotiations pose problems for all: QFs typically ask for variations of up-front price security or certainty so they can finance projects, and utilities are faced with ensuring the nonstandard contract has suitable terms to make it a secure venture for them and their ratepayers; further, operating under our regulation, utilities are concerned about ultimate cost recovery, and worry that the prudence of nonstan- dard contracts may be successfully challeged in their energy cost recovery proceedings. Also, the long-term value of new QF capacity in the utilities’ resource plans is not fully reflected by the existing standard offers which base prices on fluctuating short-run avoided utility cost (see D.82-01-103, p 67). It is, then, in everyone’s interest that a standard offer based on long-run avoided cost be adopted. The threshold problem is how can long-run avoided costs be determined. Dealing with short-run avoided costs was difficult, but the problems were surmounted and standard offers are in place. However, to value QF power reasonably in the long run, we must make many assumptions about the utilities’ future genera- tion mix and costs. While we deal extensively with forecasting the future when ratemaking, the view is only 1-3 years. This does not mean we cannot project the value of QF power for longer periods, say 10-15 years; but it means that the method used to forecast the value of QF power must be one that is not biased at the outset with a likelihood of being too high or too low when, after the test of time, payments to QFs under the forecast are compared to actual avoided costs. Or, from the ratepayer’s perspective, there must be an even chance that the forecast will be too high as too low. There are different ways of arriving at estimates of long-run avoided costs, and the future value of QF power, but all involve proxies or the creation of a utility’s generation mix and costs on a composite basis viewed at some future time. The “generation resource plan” approach, for example, would evaluate the (weighted) capacity and energy costs associated with the utility’s projected mix of resource additions without the availability of QF power. Some (not the utilities) prefer using a coal plant as the A-6 assumed resource addition that would be deferred by long-term QF power. Another method, discussed later in this opinion, is forecasting short-run avoided costs into the future to capture a proxy of future conditions. Under this approach, the value of QF power is computed on the general assumption that the utility does not make any new plant investments except in some short run peaking capacity to maintain system reliability. Once this value is quantified then various options for paying QFs for their value are applied. Obviously, the longer the forecast the more problematical it is to rely on for valuing QF power and paying QFs, in that we are committed to treating the prices paid under the standard office as per se reasonable, to be passed on to ratepayers. Some may contend that prices fixed under long-term forecasts can, at least at times, be above actual avoided costs, and therefore both: (1) PURPA will be violated in that payments will exceed avoided costs, and (2) the ratepayers will pay too much. We think the proper view and test is whether over the course of a long-term contract, despite periodic swings in actual avoided costs both above and below a forecast, the prices reasonably compensate QFs for their value in avoiding a utility’s costs, and keep the ratepayer economically indifferent to whether the generation was performed by the utility or a QF. As long as there is equal likelihood that swings in actual avoided costs are both below and above the forecast, over the term of forecast based prices, we think the spirit and letter of PURPA are followed. More troublesome, perhaps, for some is that we are adopting long-term standard offers based on forecasts of escalating avoided utility costs when there is no current capacity shortage among California utilities. The question becomes: why stimulate QF projects which cannot now proceed in the generation marketplace, under the existing as-available or firm capacity offers based on short-run costs, by adopting offers based on long-run utility avoided costs? The answer is that standard offers based on long- run avoided costs are for long-term contract commitments. We would rather err on the side of trying to have QF capacity steadily come on line over time, than on that of ultimately risking a critical capacity shortage because we did not take reasonable steps to afford an opportunity for QF power, particularly long- A-7 term capacity, to be steadily developed. Many of the QF projects that may materialize because of the standard offers we adopt today may not come on line for several years. Also, developing QF power means California will be better able to meet its power needs from within its borders, and the State’s resources will be more fully and efficiently used. Finally, we have never said that QF power must be developed at any cost, but rather that it should be developed with reasonable cost to ratepayers when viewed in the longer-term perspective. In the long run, if we do a reasonable job of valuing and pricing QF power, the ratepayers should be indifferent as to whether eventually needed capacity is supplied by QFs or electric utilities. Ill. PROCEDURAL HISTORY A. General A first prehearing conference was held on July 19, 1982 before Administrative Law Judge (ALJ) Myers. Although hearings were not scheduled, procedural issues were raised. On November 18, 1982 we issued a report on the general issued involved in devising standard offers based on long-run avoided costs, and requested comments. We did this primarily to stimulate thinking among the parties on these issues, and to see if there was any consensus on the very tentative conclusions we had reached at that time. Eighteen parties filed comments. Then, on May 4, 1983 we issued D.83-05-038, which set a negotiating conference start- ing on May 23 at Hastings College of the Law. It was our hope that with good faith negotiations between the utilities, QF inter- ests, our staff, and other interested parties, some tentative agree- ment could be reached about a standard offer(s); any agreed upon standard offer would, of course, require our ratification. The ground rules of the negotiating conference were that any standard offers to be proposed to us for consideration should be completely worked out i1 final form, and that the assent of all interests at the negotiating conference was required before a standard offer would be proposed; this was essential to protect the rights of all parties since there were no evidentiary hearings. The goal, among the parties, was to attempt to develop an interim standard offer which, while not perhaps the perfect preferred A-8 solution from their individual perspectives, would be one which they could comfortably tolerate and work under while refinement and “perfection” could be pursued in subsequent evidentiary hearings. Their understanding, based on our procedural plans as communicated by our ALJ, was that if we approved an agreed upon standard offer it would be an interim measure, subject only to change prospectively after formal hearings. It was also under- stood that the “final” Standard Offer #4 resulting from eviden- tiary hearings could, if appropriate after further evaluation, be based on an avoided cost methodology and/or pricing structure that differs from the interim order. The negotiating conference concluded on June 24, 1983. The ALJ directed the three utilities to amend their respective applica- tions no later than July 11, 1983; their amendments would contain proposed standard offers, complete with contract language, that precisely reflected the consensus agreement reached at the nego- tiating conference. The ALJ then set a second prehearing confer- ence on Friday, July 22, 1983 to allow parties an opportunity to indicate whether the proposed standard offers should be allowed to go into effect by this Commission pending evidentiary hearings on the multitude of issues surrounding pricing QF power. Again, parties understood throughout the negotiating conference that if it produced some “negotiated” standard offers, which the Commis- sion subsequently approved, they would be afforded an opportu- nity through the hearing process to propose modifications for prospective applications. B. The Negotiating Conference Process This was the first negotiating conference formally arranged and hosted by us. In some respects it is a frustrating process, because consensus building in a relatively unstructured arena (as com- pared to our hearing process) can be cumbersome. On the other hand, particularly if time limits are set, some consensus can be reached relatively quickly, whereas adversarial hearings on such a complex subject with a polarity of positions can take months longer. This is not to say the negotiating conference was nonadversarial; we understand it was adversarial. In fact, a critical ingredient of this process is that all sides are represented with near-equal resources and clout. A-9 We were fortunate to have our staff coordinated and repre- sented by the Director of the Utilities Division. We would be greatly concerned if our staff had not been an aggressive and key negotiating party, for it would raise the specter of utilities perhaps ultimately reaching the point with QFs of saying, in effect: your proposals do not sound fair, but since our cost recovery is virtually guaranteed if prices are paid under Commission ratified standard offers, what do we care-—-we will go along. However, neither consensus resolution of issues nor routinely seeking to split the difference, necessarily guarantees the best resolution from the standpoint of the public interest, which is why we must be guarded and very selective in deciding when to use the negotiating conference procedure, and in evaluating its results. We note from the prehearing conference that some QF representatives seem to feel that too much emphasis is placed on whether our staff, as a participant in negotiations, agrees on how an issue is resolved. Vigorous staff participation is an essential ingredient in any arena, and if some parties find staffs direct participation troublesome, it is probably a good indication our staff is doing the aggressive and thorough job we expect. The most critical aspect of this process is that each agreed upon standard offer resulting from the negotiating conference is presented to us on a take-it-or-leave-it basis. Each was truly negotiated as a “package”, comprised of cost forecasts, prices, and contract terms, etc. We are, at this juncture, without an evidentiary record upon which to weigh various proposals and adopt a standard offer reflecting a careful weighing of various components. Essentially, then, we face either accepting or re- jecting each of the three standard offer payment options as negotiated, and we do not, in fairness to the parties, have the latitude to make modifications. C. The Second Prehearing Conference At the second prehearing conference on July 22, 1983 a number of QFs indicated that while there was substantial agree- ment that two of the payment options under Standard Offer #4 were complete and acceptable, there were serious reservations remaining with respect to: A-10 1. Option #3, or the forecasted incremental energy rate option, as filed by PG&E and SDG&E; they found Edison’s acceptable because they liked Edison’s forecast. 2. Option #4, filed by PG&E only, which is a forecasted energy floor price payment option. This was an option not fully developed or addressed during the negotiating conference. QFs, essentially, asked that the negotiating conference be resumed or that they be allowed to pursue ad hoc negotiations with utilities. They stated a preference not to pursue refining Options #1 and #2 until ail issues, from their perspective, relating to all four payment options are resolved. Also, they expressed the opinion that the “Regulatory Authority” clause in Edison’s and SDG&E’s proposed standard offer must be elimi- nated, and the issue about contract switching must be resolved. After conferring with the assigned Commissioner, the ALJ ruled that the prehearing conference would be continued to August 8, 1983, for the specific purpose of allowing utilities to address concerns QFs has about contract language pertaining to Options #1 and #2. Also, he announced that the QFs’ request to reopen the negotiating conference would be addressed by the Commission in this decision. QF representatives then listed the particular contract language and areas which, from their perspec- tive, needed nonsubstantive changes so the contracts, mechani- cally, conformed to the agreement reached at the negotiating conference. Given the list of specified contract language “problem areas”, the ALJ directed the utilities to review their contract language with QFs and staff, and to distribute any revised page before the prehearing conference continued. They were directed not to “negotiate”, but, rather, to work together to ensure that the contract language is clear and carries out the intent of the negotiated settlement. The ALJ announced that the Commission would address the interrelated issues of contract switching and the contracts’ regulatory authority clause in its decision; those issues are discussed later in this opinion. On August 8 the prehearing conference resumed. An opportu- nity was extended to all parties to address whether the proposed | A-11 Standard Offer #4 payment options should go into effect, whether evidentiary hearings should be held and, if so, what issues should be addressed. There was an array of positions on these matters, as well as on whether the negotiating conference should be reopened. Edison and SDG&E think the three payment options proposed with Standard Offer #4 should go into effect, and that before hearings are held the reaction and experience under those pay- ment options should be studied and evaluated. Neither utility proposed a floor price mechanism as PG&E did, and they think such a conceptual payment option needs considerable study. PG&E thinks all four of its proposed payment options should go into effect, and it too thinks we should hold off going to hearing until we gain some marketplace experience with interim Standard Officer [sic] #4. While some QFs think further negotiations on PG&E’s incremental energy rate forecast would be fruitful (e.g., result in a more favorable forecast), PG&E indicates further negotiations would be futile (PHC transcript, page 156). Edison indicates that at some point the entire areas of costing methodol- ogy, payment stream options and, more narrowly security provi- sions for contracts, should be scrutinized in hearings. Our staff thinks all the payment options, except the floor price mechanism proposed by PG&E, should go into effect on an interim basis. The floor price mechanism warrants thorough review from the standpoint of ensuring ratepayer economic indif- ference and protection, and staff believes some “workshop” forum in conjunction with or before evidentiary hearings might be fruitful. Staff is not convinced that this particular payment option can be quickly resolved by negotiations. Staff believes that further efforts at negotiating the incremental energy rate forecast of SDG&E and PG&E so they are acceptable to more QFs would probably not be fruitful. Staff thinks at this juncture the entire subject of costing methodology, valuing long-term QF power, and pricing streams should be the subject of evidentiary hearings. The California Energy Commission and the State Solid Waste Management Board both want us to direct further negotiations aimed specifically at having SDG&E and PG&E develop incre- A-12 mental energy rate forecasts more favorable to QFs, and adopting a floor price mechanism payment option. None of the QF representatives who made statements at the prehearing conference had any objection to Payment Options #1 and #2 going into effect for all three utilities. They all thought Edison’s Option #3 was acceptable, because they prefer Edison’s incremental energy rate forecast over that of either SDG&E or PG&E. Contrary to the views of PG&E, SDG&E and Staff, QFs almost uniformly believe if we direct more negotiations on the incremental energy rate forecasts of PG&E and SDG&E the end result will be more favorable forecasts. We note at this juncture that if we ordered more negotiations on the incremental energy rate forecasts of only two of the three utilities, our action would be taken as a strong signal that we have reason to believe their forecasts are too unfavorable to QFs. We have no facts or evidence to lead us to such a presumption; all we know is that some QFs say they need and would prefer more favorable fore- casts. QFs all seem to indicate that if we do not order further negotiations aimed at these forecasts, then we should authorize the incremental energy rate forecast payment option as proposed by SDG&E and PG&E because some QFs may be able to use those payment options. QFs think the latest floor price mechanism payment option proposed by PG&E is acceptable, and that if we do not totally approve it, and direct the other utilities to include it in their respective standard offers, then we should at least clearly embrace the concept and direct it to be the subject of further negotiations. A-13 Other points raised by some QF representatives are: 1. We ought to clarify whether utilities can still pursue nonstandard contracts with potential QFs who do not find one of the standard offers use ful. 2. The question of whether QFs already under contract may switch to Standard Offer #4 should be addressed and resolved, preferably with the result being freedom to switch; and, likewise, whether subsequent versions of Standard Offer #4 that may result after hearings should then be freely available retroactively to QFs who signed a contract under negotiated Standard Offer #4. Both issues are addressed later in this opinion. Some QFs want evidentiary hearings, primarily to develop a permanent costing methodology for valuing long-term QF power, to resolve the need for security provisions in contracts, and to pursue adopting methodologies and/or forecasts that are readily verifiable. On this latter point, one goal almost all QFs share is having utilities use a common forecast of long-run marginal costs for pricing QF power and for utility resource planning purposes. This, they say, would result in QFs no longer being “whipsawed”’ by utilities, which are the ultimate data repositories, using differ- ent forecasts for different purposes. IV. LIMITATIONS ON THE AVAILABILITY OF THE ADOPTED STANDARD OFFER AND CONTRACT SWITCHING The standard offers we have already adopted are based on utilities’ short-run avoided costs, and they set prices which can fluctuate, but which closely parallel actual avoided costs. How- ever, the standard offer addressed by this opinion involve projec- tions, assumed proxies, and payment stream certainty which can have a visible impact on electric bills. This standard offer is the first with such characteristics, and there will undoubtedly be refinements and modifications adopted, for prospective applica- tion, as time goes by and experience is gained. We will adopt some overali limitations on the use of this interim standard offer in recognition that we are not convinced A-14 that it is a permanent all-inclusive solution. Parties agreed, at the negotiating conference, to recommend that the negotiated stan- dard offer be allowed to remain in effect at least six months, but no more than two years. It will probably be at least six months before hearings conclude, so we have no difficulty ordering the offers ratified by this decision to be in effect for at least six months, and until further order. SDG&E requests that its forecast of marginal operating costs underlying its energy prices be used for a maximum of six months; that issue will be addressed later in this opinion. Am important point for our resolution is whether existing QFs, already in production and under contract, should be eligible for the standard offer adopted in this decision. At the negotiating conference the utilities asked for some clarification, wanting to avoid a morass of uncertainty and contract administration problems. None of the participants had specific suggestions at the negotiating conference, but all seemed to want some clarity. ALJ Alderson promised to bring the matter to the Commission’s attention for resolution. In the past, when the entire subject of devising standard offers was in its infancy and the existing standard offers based on short- run avoided costs were evolving, we allowed QFs under contract to switch to the standard offer based on short-run costs which ultimately evolved (D.82-01-103, mimeo page 145); subsequently we said: “QFs may not switch from one standard offer to another, but may adopt the final version of the particular offer signed” (D.82-12-120, issued December 30, 1982, in A.82-03-26 et al.. mimeo page 118). We think there are overall problems with contract switching, and the preferred approach in this instance, particularly since the standard offer before us is so fully developed with all contract terms and complete with fixed prices, is for QFs to evaluate it from the basis of making a long-term commitment, for a 15-year minimum term is involved. Accordingly, QFs who sign up under one of the options under this standard offer, albiet interim in one sense, will not be allowed to switch later; they must wait until the end of their contract term. A-15 With respect to QFs already in production, we will allow them to sign up under this standard offer only if they are no longer under contract; QFs who have decided to produce under existing standard offers, and who entered a contract, should be bound by their decision. Some standard and nonstandard contracts have provisions which allow QFs to elect standard offers which may be approved subsequent to their entering the nonstandard contract. However, the standard offer approved by this decision represents only an interim solution, subject to change after hearings, for prospective application. As such, since we are adopting a standard offer without an evidentiary record, we are not comfortable allowing QFs under contract, even nonstandard contracts, the switch. QFs under standard and nonstandard contracts, with provisions clearly allowing them to switch, may switch after a final standard offer comes into existence after hearing, but for the time being they will have to honor their commitment under the contracts they entered. A critical factor in our thinking is that this standard offer, and the procedures leading to it, resulted primarily from our goal to encourage new QF projects which have not yet obtained financing or otherwise entered a contract and started production. Finally, we will limit the levelization payment option under this standard offer to new QF facilities or those which have never produced and sold power. This is because, with some reluctance, we approve the levelization option as a stimulus for new QF projects, and it is not reasonable for ratepayers to bear the cost of levelization in the early years to benefit a QF project or facility which has already managed to obtain financing and start production. A subject so closely related to contract availability and switch- ing warrants discussion at this point, is our concern about QFs breaching, or otherwise altering the contracts entered under Standard Offer #4. PG&E’s amended application summarizes the overall underly- ing concern about fixing QF payments based on a forecast or, for that matter, any proxy of anticipated utility avoided costs: A-16 “We can be certain that actual avoided costs will differ from the forecasts. Locking into a forecast in a rigid way assures that there will be economic losers—either QFs or ratepay- ers—in the future, because actual avoided costs will either be above or below the forecast. Staff believes that a disadvan- taged party won’t mind, because there had been an equal chance of being the economic ‘winner’ at the time the contract was executed. This is good theory, but it defies experience. If one party is seriously disadvantaged by a contract, it will have strong motivation to breach or alter the contract, regardless of how reasonable the contract appeared when it was signed. “Similarly, PGandE expects that if QFs are disadvantaged by the forecast price options, they will do everything possible to renegotiate, terminate, or otherwise escape their obliga- tions. We have attempted to write the contract to avoid this, but with the amount of money potentially at stake, ways may be found. Conversely, if ratepayers are harmed, we expect accusing fingers to be pointed at PGandE and at the Com- mission. We trust a future commission would abide by a decision of this one and allow costs to be recovered.” (PG&E amended application, Exhibit A, page 4). We think, QFs may be “winners” at times and “losers” at others, when, at any point in time, originally forecasted avoided costs are compared to actual. However, the recent volatility in short term utility avoided costs caused by oil price fluctuations will probably be borne in mind by QFs electing one of the forecast based payment options under Standard Offer #4. Accordingly, we believe they will think long and hard before seriously attempting to terminate early or to breach their contract. However, we agree with PG&E that some QFs under long term Standard Offer #4 contracts may seek to get out of those contracts if actual avoided cost conditions, particularly over a fairly long duration, would be to their advantage (despite the potential for damages generally A-17 and specific minimum damages clauses in some of the contracts).' We think it is reasonable to order that utilities are under no obligation to enter into any power purchase contract, even under one of the otherwise available Commission approved standard offers, with a QF who has terminated early or breached under Standard Offer #4, payment options approved by this decision, if damages have not been collected. By damages we mean the utility either having collected at least the minimum damages, if the contract has a minimum damages clause, and foreseeable dam- ages if their is no applicable minimum damages clause. Parties should honor their contractual commitments, and we think our making it unattractive for QFs to terminate or switch contracts is only fair, as it balances the risk ratepayers are assuming at the Outset with this long-term, forecast based, fixed price, standard offer. While this issue was not specifically raised at the negotiat- ing conference, we think it is our prerogative to take reasonable steps to minimize contract evasion; indeed, under the circum- stances it is our duty to the ratepayers. V. THE STRUCTURE OF STANDARD OFFER #4 AND FUTURE CONTRACT LANGUAGE CONSISTENCY This opinion will address what is called Standard Offer #4, which contains several payment options. Standard Offer #1 was adopted by D.82-12-120, and is for as-available energy payments; #2 is for firm capacity, and #3 is for smaller QF projects (under 100 kW). The Standard Offer #4 contracts proposed by each of the three utilities has some common contract terms that apply for all options, and specific terms covering the individual payment options. The filed contracts are complete with the agreed upon forecasts, upon which prices will be paid. Each utility chose its own format and contract language, with the goal, however, of all being consistent in substance (with the ' Minimum damages clauses apply to capacity payments when the firm capacity option is selected for capacity payments, and for energy payments when a levelized payment option is selected. Aside from the minimum damages clauses, utilities may pursue foreseeable damages as apply in any breach of contract situation. A-18 exception of certain agreed to utility specific terms, such as curtailment). As experience is gained with standard offers, and QF power purchase contracts generally, uniform standard con- tract language should be used by all utilities, except for terms which must clearly be utility specific because of substantitive differences. The convenience of standard language will greatly aid those who must review standard offers. We are disappointed this could not have been done for Standard Offer #4 in the context of the negotiating conference, but it appears time did not permit it. Rather than to simply pick one of the utilities’ contracts and order that language used by the others, we will direct the utilities to work together, with our staff, in proposing one form of Standard Offer #4 with uniform language (except where terms must be utility specific). Six months will be allowed for this undertaking, and the product shall be presented during the subsequent hearings for review. That, we think, is adequate time for the three utilities’ and our staff to harmoniously come to some common terms. QFs will have an opportunity to address the uniform Standard Offer in subsequent hearings. Once adopted standard offers are uniform for all utilities, it will be far easier to review and consider proposed changes, and to subsequently review any filed standard offer contracts in the future for compliance with Commission direc- tives. As it now stands, for example, we, our staff, and interested parties, must review three very thick contracts and engage in cumbersome, confusing and time consuming cross-checking. We think consistency would be an enlightened step which, in the long run, will work to everyone’s advantage. VI. RAMPED-UP AND LEVELIZED LONG-TERM EN- ERGY AND CAPACITY PAYMENT OPTIONS UNDER STANDARD OFFER #4 (OPTIONS #1 AND #2) Two energy payment options under the standard offer were proposed which warrant separate discussion because they share the same costing methodology, but have different payment streams. A-19 Option #1: Payment stream fixed for 10 years,’ and follows a ramped-up forecast. Option #2: Payment stream fixed for 10 years and levelized.? A. Common Elements: Before addressing the specific differences, (primarily the issue of security), we will describe the common elements. Contract term: The minimum term is 15 years, and the maximum is 30 years (Utilities should amend their contracts to specify the agreed upon maximum term). Operation date. The QF project must be on line within 5 years from the date the agreement is executed. However, the QF agrees to the payment stream, based on the forecast, when the contract is signed. This means utilities must have a 15-year forecast when the contract is signed to allow for a maximum 5- year hiatus before operation and payments start after contract execution. QFs can, however, under the negotiated standard offer, make an election within ninety days before production starts on whether they will be paid under the ramped-up or levelized forecast. Thus, while both payment streams are known and fixed when the QF signs a contract, a QF can hold off with its final payment stream election and evaluate its requirements and condi- tions shortly before production begins. Forecasts Underlying Contract Prices: The total utility avoided cost underiying the payment streams is technically com- posed of two elements: (1) avoided shortage costs, related to the peaking capacity the utility can avoid (based on the rental value of a combustion turbine), and; (2) system marginal operating costs, called the “energy” portion of the total avoided cost.’ The > Ten years if the contract term is 20 years or more, but % of the contract term if the total contract term is less than 20 years. >The appropriate standard for evaluating future utility and QF projects is a forecast of utility’s marginal energy cost plus shortage cost. This is only a proxy for a forecast of average marginal composite energy cost and capacity cost. The shortgage cost is not literally the “capacity” A-20 forecasts accompanying the filed standard offers were agreed to at the negotiating conference; while some may think they are too high, and others that they are too low, nevertheless they were agreed to. Whether the forecasts should be revised, for prospec- tive application to new contracts, can be addressed in the subse- quent hearings. The following schedules show the forecast energy portion of the total avoided cost for each utility. For illustrative purposes, the table for PG&E shows the price by time of delivery as well as the annual average price, only the annual average prices for Edison and SDG&E are shown: Pacific Gas and Electric Company Forecasted Energy Price Schedule Forecasted Energy Prices*, ¢/kWh Year of Period A (Winter) Period B (Summer) Energy On- Partial- Off- On- Partial- Off- Annual Deliveries Peak Peak Peak Peak Peak Peak Average NE 5.36 5.12 4.94 5.44 5.31 5.19 5.18 SN 6 Gie x's 44 5.66 5.40 5.22 5.74 5.61 5.48 5.47 Acca Kas 5.75 5.48 5.30 5.83 5.69 5.56 5.55 araer 5.99 5.72 5.52 6.08 5.94 5.80 5.79 ee as Deh ues 6.38 6.08 5.88 6.47 6.32 6.17 6.18 _ ES 6.94 6.62 6.39 7.03 6.87 6.7) 6.70 RP eee 7.60 7.25 7.00 7.70 7.53 7.35 7.34 NS ia ate 8.12 7.74 7.48 8.23 8.04 7.85 7.84 SEs Vase os 8.64 8.24 7.96 8.75 8.56 8.35 8.34 ES wainia'e nie 9.33 8.90 8.60 9.46 9.24 9.02 9.01 Sa 10.10 9.63 936 10.23 10.00 9.76 9.75 eS . 10.91 10.41 1006 1106 1081 10.55 10.54 PCS ee 11.79 11.25 10.87 11.96 11.68 11.40 11.39 ee 12.67 12.009 11.68 12.85 12.56 12.25 12.24 SR ie 13.61 12.98 12.54 13.79 13.48 13.15 13.14 * These prices are differentiated by the time periods as defined in PG&E’s standard offer, the time periods are subject to change in accord with how peak, partial peak, and off peak is defined in payment nor is the system marginal operating cost the “energy” cost, but that terminology has evolved into this long-run standard offer proceeding from the short-run standard offer proceedings. This is one complexity among many relating to avoided cost forecasting that will be addressed in the evidentiary hearings. A-21 PG&E’s tariff schedules applicable to large industrial customers. PG&E, Edison, and SDG&E Forecasted Energy Price Schedule, Annual Average (¢/kWh) Year PG&E Edison SDG&E die is bk Sakae pant et ee 5.18 5.30 a I rs Gch alae ent 5.47 5.60 5.90 eis 65s cae ciate ied me 5.55 5.70 6.40 as ead eae sai hae oo 5.79 6.00 6.40 EN fe oe rena yak ces 6.16 6.40 6.30 Sad le au Six Oe bak wk ok be 6.70 6.90 6.70 a hss x60 5 ead tales 7.34 7.69 7.90 SR DOERR IIE RD Ore ee 7.84 8.10 8.60 Ss ys bas ove ks ee aware 8.34 8.60 9.20 PG Sia) bani ehhaleeb et 9.61 9.30 10.00 pe ra Dapper eases Senne 9.75 10.10 10.30 rye sete bias odes wit 10.54 10.90 11.10 PEAS nee ee ee 11.39 11.80 11.80 tS oe er Ae 12.24 12.60 12.60 er Se tee a ans 13.14 13.60 13.40 aE Pan ener ga rr iy Eee — — 14.20 The preceding schedules show the 15-year forecasts of avoided marginal energy costs, which is, of course, one component of total avoided costs. In understanding how total contract prices are derived, it is critical to keep in mind there are a number of mix-and-match options for both energy and shortage cost or capacity payments. For example, a QF can elect to sell part of its output under the terms of one of the existing standard offers based on short-run avoided costs; if he did so, the energy sold under short-run as available or firm capacity standard offers. would be subject to price variation, whereas the portion sold under the forecast would have a fixed price. Also, different shortage cost or capacity payment options are available to QFs signing up under any of the energy payment options. A-22 Capacity payment price: QFs may elect to deliver either firm or as-delivered capacity. The QF can select how much firm capacity he will be contracted to provide, and any excess deliv- eries will receive the as-delivered capacity price. These capacity payments are determined and paid under the same terms as those in existing Standard Offers #1 an #2, for as-available and firm capacity, respectively. Thus, firm capacity payments can be levelized as provided by Standard Offer #2, and are subject to the performance bonus when the QF demonstrates a firm capacity factor in excess of 85%; all capacity payments are made monthly. The following table shows the annual average capacity payment in ¢/kWh for as-available capacity: PG&E, Edison and SDG&E Forecasted Capacity Price Schedule, Annual Average* (¢kWh) Year PG&E Edison SDG&E SRS vir rere Cee ree RS 798 .199 — Ss Sx CA SE Maa a es oT eee enes .867 .868 .700 EERE OEY OLE PERE Ee Se ere 924 924 740 PE academe eed bak eae AN e RRS 1.004 .993 .800 Neo hikca ty a ee me ON ee Coe 1.084 1.073 .870 Dek CRA ean coe enews 1.164 1.153 950 PE eT Sasa ak eho b UE MEU Sa oe .255 1.244 1.020 PEROT Oe a ee yer Pere ie err a en 1.346 1.335 1.100 Cg A ee ee res Sere were ee 1.438 1.439 1.310 ESS ke he eA A he nie aed 1.541 1.690 i.400 kek by dy ee eae Oa kee eee 1.643 1.804 1.500 MELLO EE EE CORE PPLE eer ee 1.757 Le 1.600 ae Ran Gue Kaan de hae en em kn 1.871 2.055 1.720 cs ch ek aes fio oeae eres 2.009 2.215 1.840 Wi ue ho Weg vO Ghee sao EO 2.146 2.352 1.960 hg, AE OTe CEO EE TE ee — — 2.100 * For payment purposes the annual average rate will be converted to seasonal Itime [sic] of delivery rates consistent with the Commission approved method applicable to as-available capac- ity. The annual average rate expressed in ¢/kWh, rather then $/kWh, is developed for the utilities’ capacity payment fore- A-23 casts, applying their allocation factors and hours per period currently in use. B. Forecasted Ramped-Up Payments Based on Energy or Sys- tem Marginal Operating Costs (Option #1) Option #1 is the ramped-up payment stream, with the payment varying with season and time of delivery. This provides a direct price signal to encourage peak period delivery by QFs. During the fixed price period, (maximum 10 years) the QF receives a series of predetermined energy prices for production, broken down by year and costing periods. These fixed prices per kWh are paid regardless of whether the utility’s actual avoided costs turn out to be higher or lower. QFs can choose to take a fraction (in 20% increments) of their energy payments under this option, and the remainder under the full short-run avoided costs applicable under Standard Offers #1 and #2. Oil or gas-fired cogeneration facilities are limited to receiving no more than 20% of their energy payments under the forecasted energy price option, with the remainder paid at the full short-run avoided operating costs under other existing standard offers, or under Option #3 (which is described later). After the fixed price period, (e.g. 10 years) the QF receives payment for energy delivered at the full short-run avoided operat- ing costs which are also paid to QFs under Standard Offers #1 through #3. This option contains no discounts, requires no security, and has no formula for calculating damages in the event of nonperform- ance or breach. C. Levelized Payment (Option #2) During the fixed price period, the QF will receive prices levelized over that period. The forecast from which these levelized prices are derived is the same as that used in the forecast or ramped-up energy price option. Prices are time-differentiated, and will be paid throughout the fixed price period. This option also does not require any discounts from the utility’s avoided cost. However, it does require that the QF post security to protect ratepayers in the event nonperformance occurs and early period A-24 overpayments have been made. And if the utility accepts a lesser grade of security, that may not fully guarantee protection of the ratepayer, then a 1.5% discount from the levelized prices is applied over the fixed price period (specifics concerning security and levelization are discussed below in this section). This option under PG&E’s proposed contract, contains a formula for calculat- ing minimum damages in the event of breach; however utilities may also seek to collect foreseeable damages allowed at law for breach of contract, beyond those specified by the formula. 1. Levelization This is an opportune place to discuss levelization generally, because the distinguishing feature of payment Option #2 is a levelized payment stream. Levelization is a payment stream where periodic payments are constant over a period of time, and are based on forecasted values and the value of money. It works roughly as follows: | zs sayment stream “ ~ sme The payor (e.g., utilities and ultimately their ratepayers) ap- plies a discount rate to the ramped-up payment forecast in order to derive an “equivalent” levelized payment stream. As indicated in the above diagram, the result of levelization is that the payor pays a higher level of payments earlier in the time period (area A on diagram) in exchange for lower payments later on (area B on diagram). The payment streams are “equivalent” if, given the payor’s opportunities to invest funds (or cost of capital), the savings in the later years (area B) are equivalent to the return that the payor could have earned investing the difference between ———— A-25 the forecasted and levelized payments (area A) early on. The discount rate is that rate of “foregone” compound interest at which the payor is willing to trade for the burden of paying more sooner than would otherwise be the case. Applied to QF-utility contracts, levelization means the utility will be paying more in the earlier period, and electric rates for consumers in the early period will be incrementally higher as the periodic levelized payments are passed on in the utility’s rates. Also, if the QF quits production before the end of the levelization overpayment, (time X on the above diagram), the utility and ratepayers are left having paid more than the commodity was valued. Our concern about levelization stems from these factors. In simplest terms, levelization for QF pricing is a form of ratepayer “loan” to make a perhaps otherwise nonfinanceable QF project viable enough to attract conventional financing. QFs say the option of levelization, which is comparable to ratepayers than their “financing” of utility-owned projects, is only fair. Staff thinks a solid QF project should be financeable if it has a guaranteed price stream, as under Option 1, and that a bank or other investor should make the “loan” needed in early years instead of the ratepayers. But staff agreed to this levelization option on an interim basis to see how effectively it facilitates new QF projects and to see how risky it actually is to ratepayers. The discount rate negotiated at the conference, to be used in the utilities’ levelization calculations, was 15%.* If something less than first class security (as discussed later) is put up by the QF to ensure ratepayer recovery for overpayments in the event of nonperformance, an additional 1'2% is taken directly off the levelized payment stream to compensate ratepayers for the corre- spondingly higher risk resulting from a lesser grade of security. There was considerable debate among parties as to the appropri- ate “opportunity cost of capital’ for ratepayers in levelizing payment streams for projects of varying technical and financial risk. If the discount rate used it too high, then ratepayers are not * PG&E included levelization based payments with both a 132% and 15% discount rate; however, it shall use 15%, consistent with the agreement reached at the negotiating conference. A-26 fully compensated for the overpayments in the early years of the contract; that is, the levelized payment stream is too high. Levelization and its attendant problems posed by the use of discounting, security requirements and termination penalties is something which, in a perfect world, we would prefer not to deal with, particularly in the context of a standard offer. We have severa! concerns about levelization as a feature of even an interim standard offer: (1) the precedent may lead parties to believe it is the norm; (2) administering the security provisions of standard offer contracts with levelization can, as the number of QFs increase, be an ongoing administrative chore of some magnitude for utilities (which ultimately translates into additional costs to ratepayers); and (3) costs to ratepayers from early contract period “overpay- ment” caused by levelization acerbates the overall level of electric rates, which are now higher than we prefer. We wonder why a large number of QF projects cannot be financed with the simple forecasted payment stream, which is guaranteed, assuming performance, up to the first ten years of operation. The forecasted ramped-up payment stream offered by the nonlevelization option is a large step forward in terms of payment certainty for QFs, which should greatly assist with financing. The specter of many levelized standard offer contracts concerns us; particularly since we have no evidentiary record that shows solid viable QF projects cannot be developed or financed without levelization. Our solution is to allow utilities to enter levelized standard offer based contracts for a maximum of one year after the effective date of the [sic] this order. As indicated in the following order, we will address lissues [sic] relating to this payment option as early as possible in evidentiary hearings. And Ithis [sic] option may be extended though [sic] a subsequent interim order, if we determine that providing for levelization in a standard offer is in the continuing public interest. Those who represent QFs have the burden of showing why levelization is necessary. Our goal is not to | A-27 ensure every possible QG [sic] project and/or technology is financeable; rather, our goal is to provide an economic environ- ment in which solid, well-conceived projects have a reasonable opportunity to be financed through prices paid by utilities and ratepayers. It is not our task to compensate, through standard offer payment terms, for all concerns and reluctance of lenders and equity investors. Ours is a world of risks, and we have no business ensuring that some have little or virtually no risk at the expense of others (i.e., ratepayers). While we will ratify the levelized option for use for one year, one purpose of this discus- sion is to alert parties directly that we have serious reservations about continuing to provide for levelization in a standard offer. 2. Security Provisions of Levelized Option #2 PG&E very aptly summarizes how the issue of security provi- sions evolved in the context of the levelization option: “This proved to be one of the most troublesome issues in the Settlement Conference. Commission staff wanted QFs to provide very solid, substantive security in order to assure ratepayers would be made whole in the event of termination or nonperformance. QFs wanted the opportunity to substi- tute lesser security (e.g., liens on their equipment) which is more readily affordable, and to allow utilities to exercise discretion in rejecting any ‘inadequate’ security that might be offered. Utilities were not anxious to have such discretion within a Standard Offer, because it appeared to present a no- win situation. The QF developer whose proposed security was rejected by the utility could complain that the utility was being unreasonable; if security that the utility accepted eventually turned out to be inadequate, its prudence could be questioned by the Commission. The result is a compromise. Two tiers of security will be accepted. QFs that provide first class security will be abie to avoid price discounts; those that provide lesser security will be subject to a 1.5% energy price discount in the fixed price period. This lesser security—essentially corporate guarantees and equipment liens—is subject to acceptance by the utility. PGandE agreed to this discretionary authority because QFs A-28 insisted they needed the option of providing lesser security. PGandE reluctantly accepts this discretionary role in this Standard Offer and hopes that in any future recovery pro- ceedings, the Commission will view its exercise of such discretion within the greater context of promoting alternative energy resources.” (PG&E’s third amended application, pages 15 and 16 of Appendix A). The higher quality security, the amount of which changes each year as ratepayer exposure is reduced until the levelization mid or crossover point is reached, is any or a combination of the following: A letter of credit, performance bond, paid-up non- cancellable project failure insurance or a solid corporate guaran- tee acceptable to the utility. Lesser security is other security which is acceptable to the utility, such as: a less solidcorporate [sic] guarantee, and liens or a mortgage on the facility and/or the land on which it is located. Staff believes that if the utilities have diseretion to reject second level security, that potential QFs should not be able to appeal the utilities’ decision te the Commission. We agree. The ability to provide second level security is a major concession to responsibility of judging it. The utilities should not be second- guessed, and we do not want the responsibility for judging security in individual cases. We expect the evidentiary hearings to develop even clearer security requirements for this standard offer. A standard offer should not have discretionary iterms [sic] in it. Having utilities administer these security provisions is directly analagous [sic] to their serving in the role as a lender, which in a real sense they are (with the ratepayers’ money). We can under- stand their discomfort in this role, but we think the guidelines are clear enough they can reasonably administer the security provi- sions. Ultimately, however, we would prefer more concrete secur- ity provisions if levelization options are extended, and we expect this issue to be addressed in the evidentiary hearings. directly analogous to their serving in the role as a lender, which in a real sense they are (with the ratepayers’ money). We can understand their discomfort in this role, but we think the guidelines are clear enough they can reasonably administer the security provisions. Ultimately, however, we would prefer more concrete security A-29 provisions if levelization options are extended, and we expect this issue to be addressed in the evidentiary hearings. [sic] D. Curtailment Provisions (Under All Payment Options) The negotiated curtailment provisions for Standard Offer #4 are utility specific, with PG&E’s provisions consisting of the following 2 options: (a) Curtailment under “negative avoided cost” conditions and a lower “hydro spill rate” under hydro spill conditions with no hourly limit. This option refers directly to this Commission’s definition of negative avoided costs:and hydro spill conditions. (b) A limit of 1,000 hours of real time prices per year for negative avoided cost, hydro spill and non-oil/ gas units at the margin. This second option requires some further explana- tion, as PG&E explains: “PGandE will not curtail the QF when these conditions occur, but will instead offer to continue purchases at a price equal to the current actual avoided energy cost. The QF can then make its own operating decisions; PGandE and ratepayers will be indifferent. PGandE will limit the 1,000 hours to off-peak periods, and increase the price in the other off-peak hours to account for the fact that these low-cost periods are no longer being averaged in. “PGandE’s unique system means it will have to have maximum operating flexibility in the coming years to efficiently utilize the available resources. The 1,000-hour option helps provide this necessary flexibility while re- maining faithful to the avoided cost framework. SCE and SDGandE are not providing the opportunity for the QF to remain operational and receive actual avoided costs, but are instead offering annual hourly curtailment limits. PGandE does not believe such an approach is appropriate in its case, and would object to one being imposed”. (PG&E’s Amended Application, Exhibit A, pages 11-12). ait A-30 SDG&E’s negotiated standard offer includes provisions to cur- tail QF production for up to a total of 300 off-peak hours per year where such purchases result in “negative avoided cost” to SDG&E “as such term is defined by the CPUC (SDG&E’s Amended application, page 22).” Edison’s offer curtails the QFs production for up to 300 off- peak hours when: “(i) purchases would result in costs greater than those which Edison would incur if it did not purchase energy from seller but instead utilized an equivalent amount of energy generated from another Edison source (emphasis added), or “(ii) the Edison Electric System demand would require that Edison hydro-energy be spilled to reduce generation”. (Edison’s Amendment, page 26)° In D.82-01-103, D.82-04-071, and D.82-12-120, we defined “negative avoided costs” as a situation where, due to operational circumstances, purchases from QFs would result in costs greater than those which the utility would incur if it did not make such purchases, but instead generated an equivalent amount of energy itself. We cite such a condition as being when a baseload or large oil-fired intermediate load plant is shut down at night due to an excess of QF electricity but then cannot be restarted and brought up to its rated output for the next day’s peak load, thus necessitat- ing instead the start-up of a plant with very high generating costs (e.g., a gas turbine peaker) or an expensive emergency purchase of capacity. In D.82-04-071 the Commission concluded that, while curtailment was not appropriate for hydro spill conditions, a lower “hydro savings” price is appropriate. The decision did not, however, permit a lower price to be established during periods when economy energy is purchased or when avoided costs are positive. Anticipated economy purchases were to be averaged in the avoided cost applied for the entire time period. Proposals to restrict the number of hours that curtailment and hydro spill * The phrase “generated from another Edison source” is interpreted (by both SCE and the Commission) to exclude economy energy purchases. Hence, it conforms with Commission policy on this issue. A-31 conditions apply were denied in D.82-01-103 and D.82-04-071. However, in D.82-12-120 we directed utilities to undertake stud- ies which would be considered in reviewing future proposals to establish such limits. Only PG&E’s curtailment option a) conforms with our nar- rowly defined negative avoided cost and hydro spill conditions established for Standard Offers contracts #1 and #2. We ac- knowledge the nonconformity of PG&E’s option b) and the other utilities’ curtailment provisions with our previous decisions. How- ever, we consider these disparities as part of the negotiation process and integral to the parties arriving at a negotiated “pack- age”. We alert parties that these provisions will be reviewed and evaluated for prospective standard offers in evidentiary hearings. E. The “Regulatory Authority” Clause Edison and SDG&E have what are commonly termed “Regu- latory Authority” clauses, which allow for changing contract terms if directed by a regulatory agency. Edison’s reads as follows: “This Contract shall at ail times be subject to such changes as any regulatory agency may direct in the exercise of its jurisdiction. If there is any conflict between the provisions of this Contract and any changes directed by such regulatory agency, the Parties shall amend this Contract in a manner consistent with such regulatory changes.” Both utilities indicated they included this clause consistent with prior Commission directives with respect to earlier standard offers. PG&E indicated it was willing to drop this clause because it seems incompatible with a long-term forecast based and bind- ing contract, particularly if this Commission clearly intends to allow utility cost recovery for prices paid under standard offer contracts. In view of our holding that contracts entered under Standard Offer #4 will not be subject to retroactive change based on prospective developments in the continuing saga of pricing QF power, we think the regulatory authority clause should be deleted. In other words, the quid pro quo for giving QFs certainty with respect to all contract terms, and eliminating the regulatory j — A-32 authority clause, is that QFs may not freely switch to other contracts later, until their contract term is up, if subsequent contracts or terms appear more favorable. Thus, we are really exchanging certainty of contract sanctity for certainty of commit- ment, and given our reaffirmation that cost recovery will be allowed utilities for all standard offer power purchase contracts, we think this is only fair. QFs contend that with the regulatory authority clauses in the contracts of Edison and SDG&E there will be insurmountable hesitation by lenders because of uncer- tainty. In ordering the clauses removed we recognize that we cannot order retroactive changes to interim Standard Offer #4 contracts but, given the restrictions placed on the use and availa- bility of this negotiated standrd [sic] offer, we are willing to commit to that loss in flexibility. F. SDG&E’s Forecast of Marginal Energy Production Costs and Updating Forecasts SDG&E requests that its 15-year forecast of marginal energy and production costs and its corresponding incremental energy rate be available to price QF power under this standard offer for a maximum of six months after filing its amended application which was filed on July 11, 1983 (SDG&E’s amended applica- tion, pages 5, 9 and 12). Near the conclusion of the negotiating conference there was disagreement about the energy rate forecast SDG&E would use in connection ith its standard offer. Ultimately, SDG&E filed the forecast most parties thought was agreed to. It did this, according to its amended application, in the spirit of cooperation; however, it indicates its most current forecast is lower (SDG&E’s amended application, pages 5-6). Proposing the consensus agreed upon forecast, one SDG&E prepared in March 1983, but request- ing a maximum six month period for its availability for QF contracts, was done, according to SDG&E, at ALJ Alderson’s suggestion. Our ALJ offered that suggested compromise as a means of avoiding what seemed to be a looming and substantial impasse. We believe the substance of our ALJ’s suggestion has merit. However, rather than impose a hard and fixed time cap for use of ee | A-33 SDG&E’s filed forecast, we will direct that it be applied to Standard Offer #4 until further order; and one of the first issues we want considered at the evidentiary hearings, for expeditious consideration and decision, is the reasonableness of SDG&E’s forecast, particularly vis-a-vis the level of Edison’s and PG&E’s. This approach is preferred because we do not want to get into the situation of having a hiatus, where prices based on SDG&E’s filed forecast have lapsed, and a forecast to replace it has not been approved. Our solution reasonably addresses SDG&E’s concern. We are not prepared today to address the related questions of the frequency of updating the forecasts of all utilities, and the procedural forum or vehicles for updating. Those are issues, however, that are deserving of all parties’ attention during hear- ings. The forecasts underlying prices in interim Standard Offer #4, for the respective utilities shall, in the meantime, be used as directed in the following order. Vil. FORECASTED INCREMENTAL ENERGY RATE PAYMENTS (OPTION #3) Capacity payments under this option are the same as those described for Option #1 and #2 (as discussed). However, the energy prices under this option are based on (1) a forecast of the utilities’ incremental energy rates and, (2) actual utility costs for incremental fuel. The incremental energy rate has been referred to by some parties as the derived and/or incremental heat rate, which is incorrect. The incremental energy rate is derived from marginal energy cost forecasts taken from utilities’ production simulation models; these models include estimates of the costs of all projected resources at the margin over the term of the forecast. (e.g., 15 years). Once the marginal energy cost forecast is made it is then analyzed to determine the primary fuel for the resource most frequently at the margin, which has turned out thus far to be oil or gas. The overall annual marginal energy cost is then divided by the projected incremental fuel cost for that period to produce, for any given year, a forecast of the incremental energy rate (which is expressed in Btus/kWh). While this is similar to how heat rates are expressed, as derived it does not reflect a system incremental heat rate, because it is derived by only one fuel/resource and not a weighting of ali resources that may appear | cea A-34 at the margin at times over the forecast period. For consistency among utilities, and to avoid prolonging confusion, this payment option shall be referred to as the “incremental energy rate” option, and their contract terms and language shall be amended accordingly. Assuming oil or gas generation is the marginal, incremental, swing generation source, incremental energy costs for utilities are the product of the incremental energy rate and the price paid for oil or gas. This pricing formula and payment stream is most sought by oil and gas cogenerators, as while the forecasted utility incremental energy rate is fixed, the cost of fuel will be actual; and, of course, if the cost of utility oil and natural gas rises or falls there is a direct correlation for the QF’s corresponding costs. PG&E likes this payment option because it thinks there is less likelihood, over time, that payments to QFs will deviate from actual realized utility avoided costs (PG&E’s amended applica- tion, Exhibit H, page 9). Under PG&E’s Option #3° the QF will be paid a monthly incremental energy rate, based on a “derived” incremental heat rate forecast and the actual price of marginal fuel (i.e., natural gas or oil). However, there are revisions for making adjustments should PG&E’s actual incremental energy rate differ from the projection. The QF, when the contract is signed, can elect a series of annual band widths, expressed in 100s of Btu/kWh, which are equally applied above and below the utilty’s [sic] forecast of incremental energy rates. The lower band serves as a floor, and the upper band a ceiling. At the end of each year PG&E determines its actual price of oil and natural gas for its fossil fuel generating plants and divides this weighted cost into the energy payments made to the QF over the year. The result of this calculation is the utility's “actual” (derived) incremental energy rate. '{ the actual derived heat rate factor for the year is below the elected lower band, PG&E will make a one-time payment so the ° Although PG&E’s amended application calls this Option #4, for consistency with the other utility filings, and since PG&E’s designated Option #3 is not approved by this decision, we refer to this energy payment Option as #3. EO)” A-35 QF receives the value of the lower band for that year; if it falls above the upper limit of the band the QF makes a similar one- time payment to PG&E; finally, if it is within the limits of the band, no payment adjustment is made. Other than the specifics described above, the contract terms for Option #1 apply to this option. Thus, this option contains no discounts, requires no security and, while probably most attractive to oil and gas cogenerators, is available to all QF technologies. Once the forecast based payment stream ends, the QF will receive the then current avoided energy prices. PG&E proposes the one-time annual reconciliation adjustment, while Edison would simply compute the price and any adjustment monthly. PG&E explains why it has a different approach as foliows: “PGandE’s heat rate option differs from SCE’s in that it contains a single value per year, rather than one for each costing period, and it applies annually rather than monthly. PGandE believes that these differences reflect utility-specific differences and that it would be inappropriate to require PGandE to adopt SCE’s approach. Specifically, there ap- pears to be an asymmetry across months for HFRs on PGandE’s system. For instance, a typical year could see 2 or 3 months (in the spring) well below the annual fixed HRF, and the remaining 9 or 10 months near or slightly above it. Given a band of the proper width, this could trigger pay- ments to the QF in the spring, with no compensating payments the rest of the year. PGandE could develop a monthly mechanism such as SCE’s; however, we believe that a) it would by unnecessarily complex, b) PGandE’s structure provides sufficient pricing certainty for QFs, and c) further analysis would be required, and lower HRF [sic] values would likely result.” (PG&E’s amended application, Exhibit A page 4). We recognize the benefits of having oil and gas cogenerators on the system to displace the utilities’ incremental oil and gas generation units, but only to the extent that: 1) cogeneration results in a more efficient use of fossil fuels (i.e., the cogenerator’s ———ee A-36 actual incremental energy rate is lower than the utility’s) and, 2) California’s resource base, no matter how well it can be diversi- fied, may require some oil and gas generation units to meet demand. We are concerned, however, that this energy payment option could, over time, provide incentives to oil and gas cogener- ators that are not commensurate with the benefits described above. Whereas Options #1 and #2 place the entire risk that a QF’s actual production costs may be higher than our projections of avoided costs, Option #3 removes the risk associated with fuel- price variability from fossil-fuel cogenerators. Instead, ratepayers are exposed to all of the fuel-price variations, which can be very significant for oil and gas. Furthermore, providing a band around the incremental energy rate forecast mitigates some of the poten- tial efficienty [sic] benefits that oil and gas cognerators [sic] can add to the system. The issue of the utilitities [sic] forecast of incremental energy rates was not resolved at the negotiating conference to the satisfaction of some QFs. At the prehearing conference QFs indicated they found Edison’s filed forecast acceptable, while PG&E’s and SDG&E’s were not. QFs request to reopen the negotiating conference to pursue what, from their perspective, would be a “better” forecast from PG&E and SDG&E. So, at this juncture, we see our choices with respect to payment Option #3 of being the following: |) To approve Edison’s Option #3, and reopen the negotiating conference to consider further the other utilities’ forecasts; 2) to put all these forecasts back into the negotiating conference; 3) to allow this payment option, for all utilities, to be taken up in evidentiary hearings and approve nothing today with respect to Option #3 or, 4) to approve the use of Option #3 for all utilities, as filed, on the positive assumption that some QFs may find it useful pending a complete review of Standard Offer #4 and all payment options during evidentiary hearings, during which the feasibility of further negotiations is always an option. We think the latter approach is by far the most constructive in view of our policy reservations concerning this option and our decision, discussed later, not to reopen the negotiating conference (our reasons for not reopening the negotiating conference are A-37 discussed later). QFs, we note, who are dissatisfied with the incremental energy rate forecasts may compensate to some degree by selecting a wider band around the utility’s forecast; thus, while their minimum payments could be lower, their potential maxi- mum payment could be higher. In any event, we find allowing this payment option to go into effect extends to QFs another option and opportunity not now present. Even if only a portion of oil and gas cogenerator QFs can use this option, it is a material improve- ment over not having the option available. Also, as discussed later, QFs may seek a nonstandard contract if they find Option #3, or any other option or standard offer, does not suit their needs. The continued availability of nonstandard contracts is discussed later in this opinion. In view of the reservations discussed above, we are limiting the availability of this energy payment option to a maximum of one year after the effective date of the following order. As we determined for payment Option #2, we will not extend that period for payment Option #3 until evidentiary hearings have addressed these issues and we determine that continuing an incremental energy rate option beyond one year is in the public interest. Vill. UTILITY COST RECOVERY OF PRICES PAID UNDER STANDARD OFFER CONTRACTS WITH QFS At the negotiating conference the utilities raised concerns about their cost recovery in Energy Cost Adjustment Clause (ECAC) proceedings, assuming we approve the negotiated in- terim standard offer. They repeat the concern in their amended applications. We thought it was well understood that prices paid QFs under standard offers approved or mandated by us were per se reasona- ble for ratemaking purposes. That is one of the hallmarks of the standard offer. It would be inconsistent and unfair for us to approve the use of a standard offer and later question the reasonableness of the prices. While the world may not always be fair, in our regulatory realm this Commission would never subse- quently disallow costs necessarily incurred to pay QFs under A-38 standard offer contracts which we expressly found reasonable at the outset. The only possibility for an ECAC ratemaking adjustment would be if a utility did not diligently enforce all contract provisions which protect the ratepayers. For example, in the event of QF breach or nonperformance, we can easily foresee a ratemaking adjustment if the utility did not take all reasonable measures to collect damages or to have security called on and applied to mitigate a loss; damages and called upon security inure to the ratepayers by a credit to the ECAC balancing account. We would be derelict if we did not ensure utilities remain diligent in administering power purchase contracts on behalf of their ratepayers. But, with respect to the utilities’ greatest concern, we can only say that we cannot envision this Commission, or its successor members, ever being so patently unfair as to attempt to disallow prices paid QFs under Commission approved standard offers. IX. CONTRACT TERMS OF INTERIM STANDARD OF- FER #4 SUBJECT TO RETROACTIVE INCORPORA- TION RESULTING FROM A.82-03-26 ET AL. Since the regulatory authority clause of Standard Offer #4 is being eliminated, we must be very specific about any contract terms that are subject to retroactive change. Much of Standard Offer #4 contract language was premised on existing Standard Offers #1 and #2, which will be subject to another order in A.82- 03-26 et al. Although Standard Offer #4, as proposed, is very inclusive, there are certain contract terms which should be rea- sonably consistent with other standard offers; we can direct consistency without changing the substance of negotiated Stan- dard Offer #4. Those contract terms fall in the categories of: (1) PG&E’s line loss factor (PG&E only). (2) Interconnection procedures and requirements involv- ing Ifuture [sic] line and system upgrades. (3) Right of first refusal and mght to purchase on abandonment. a A-39 (4) Insurance requirements. We are aware, however, of the difficulty for some QFs to proceed with their projects without a definite clarification of these final contract terms. We anticipate a decision on A.82-03-26 in the near future. However, for those contracts signed by both parties prior to the effective date of a decision on A.82-03-26 et al. with respect to these terms, we will grant the QF discretion to decide, within 30 days after the effective date of our decision on A.82-03-26, whether or not the terms shall be retroactively changed in his/her contract. In this way, a QF that is ready to proceed immediately following this order will have the definitive contract terms with which to approach financial institutions and the option to have them changed retroactively. However, for any contract signed by both parties after the effective date of our decision on A.82-03-26, we order utilities to amend their respec- tive Standard Office [sic] #4 contract language and terms, for retroactive application, on the above points consistent with the outcome in A.82-03-26 et al. No other terms shall be changed by order of this Commission for retroactive application to executed Standard Offer #4 contracts. X. OPPORTUNITY FOR NONSTANDARD- CON- TRACTS BETWEEN UTILITIES AND QFS During the prehearing conference QFs asked that we address whether utilities may still negotiate nonstandard contracts if proposed Standard Offer #4 goes into effect. Our original direc- tion on this point in D.82-01-103 remains in effect; that is: utilities shall negotiate in good faith with potential QFs who do not want to contract under a standard offer. We expect utilities to continue to abide by that order. We recently addressed and amplified some significant procedural and substantive points re- lating to nonstandard contract negotiations, which are worth mentioning again for the benefit of all parties (D.83-06-109, in C.83-05-12, Friant vs PG&E, pages 4-5): “... Utilities were told to negotiate proposed nonstandard contracts in good faith with QFs not wanting to accept a standard offer, but we did not mandate a result. The man- dated obligation in terms of end result which utilities do have A-40 is to contract under the applicable adopted standard offers. As long as utilities negotiate in good faith with respect to nonstandard contracts, they fulfill our mandate with respect to those types of contracts. If we allow QFs seeking non- standard contracts to bring their preferred proposals before us for ratification, instead of utilities applying for approval only after their management thinks a nonstandard contract has merit but wants our ratification in view of cost recovery concerns, the entire negotiating process would: take a very different turn from what we envisioned. For then, QFs and utilities would in essence ultimately ‘negotiate’ with us, and not each other. We refuse to so directly interject ourselves into the arena of QF-utility negotiations. Accordingly, we will not order a ‘result’ based upon a QF’s complaint, but we will impose sanctions on a utility for bad faith negotiations. “Although the distinction we draw may seem too subtle or without solid basis from Friant’s perspective, it is deeply rooted in the role of the regulator vis-a-vis investor-owned public utilities. For ordinarily, in the absence of compelling circumstances, utility management should apply its expertise and judgment within the regulatory parameters we set; we must ensure the parameters are fair and in the overall public interest, but we should not directly ‘manage.’ By the nature of the relief Friant requests it is asking us to substitute our judgment for that of the utility‘s management. We will however make a ratemaking adjustment if we find a utility had a lower cost option for power (e.g. QF power) which it did not exercise, or otherwise acted imprudently.” XI. REOPENING THE NEGOTIATING CONFERENCE AND SCHEDULE FOR EVIDENTIARY HEARINGS QFs want to reopen the negotiating conference to pursue different derived heat rate forecasts from PG&E and SDG&E with respect to payment Option #3, and to develop a fourth payment option.’ We have decided not to reopen the negotiating ’ Early in the negotiating conference PG&E proposed an energy floor price mechanism, which had a fixed price period and a discounting mechanism in later years to compensate for the guaranteed floor price A-4] conference, but as the evidentiary hearing proceeds, we leave it to the assigned Commissioner to determine whether any negotia- tions regarding Option #3 will contribute to the ultimate decision affecting the future of Option #3 beyond the one-year period provided by this order. When we announced the settlement conference we stated it would run for four weeks. Our ALJ allowed it to go for five weeks. We knew at the outset some parties, at the conclusion of the negotiating conference, would probably either be dissatisfied with the results or want it to go longer if not everything was “settled”. That’s the essence of a negotiating session; there are inherent frustrations built into that process. The negotiating conference required a lot of staff expertise and the participation of our Utilities Division director. Five weeks is enough. Also, a negotiating conference should be held for only the period specified at the outset, otherwise parties will, for good reason, have the expectation that if they do not like the results the conference can go on and on until they do. And there is always the real, but undesirable, possibility of Parkinson’s Third Law starting to apply when we hold negotiating conferences, which, in during the fixed price period. Then, very late in the negotiating confer- ence, a variation was proposed by U. S. Windpower, but was not developed to the point of the various parties (utilities, staff and QFs) being able to reach a consensus. Of the three utilities, only PG&E developed this payment option in the amended applications. Edison and SDG&E, as our staff, think the concept may hold some promise but that it needs considerable study. Whereas all the other payment options have prices that are based either completely or substantially on a fixed forecast, PG&E’s proposed floor price mechanism makes payments to QFs, over time, based on actual utility avoided costs. However, in the early years of the contract the prices can set as a floor which can be above the levelized payment stream prices in Option #2; there is a long payback period provided for in later years if early year payments substantially exceed actual avoided costs. The payback period, depend- ing on the contract term and amount of overpayment, can by substan- tially longer than the payback period in Option #2. Thus, despite discounting factors in later years, the issue of risk assessment and security provisions become even more critical for this proposed payment option than Option #2. A-42 essence, is: work always fills the time allowed for it. Another aspect of reopening the negotiating conference for the specific purposes proposed by QFs is that it would tend to be taken by all parties that we strongly expect a certain result (e.g., that SDG&E and PG&E should raise their derived incremental energy rate (forecast), or that we conceptually embrace a payment option, such as the floor price mechanism. We have no reason to believe any of the energy rate forecasts are too low (or for that matter too high), or that the floor price mechanism payment option has conceptual merit. Taking the extraordinary step of ordering nego- tiations reopened under these circumstances would not do justice to the concept of allowing parties a fixed time to reach a negotiated consensus. As this is our first experience with a negotiating conference in a generic and complex proceeding, and substantial results have already been accomplished, we do not think it is either necessary or desirable to reopen it. We are sorry if some are disappointed by our decision on this point, but as we said earlier, that’s the negotiating process. We would have been surprised had some not been disap- pointed. At this juncture we think it is most constructive for parties to spend their time to start preparing themselves for evidentiary hearings, so their prepared showings are complete and well developed. They are free, in doing this, to exchange ideas and concepts. To ameloriate some frustration, disappointment, and possible economic forebearance, we are, as discussed above, authorizing the incremental energy rate payment Option #3 for all three utilities, and not just Edison, so that option is extended through- out most of the state. All parties must realize that while we are approving the negotiated standard offer, they should not assume the methodol- ogy underlying the derived prices and the contract terms have significant precedential value in our continuing process of adopt- ing a standard based on long-run avoided costs. When evidentiary hearings begin, parties should be prepared to examine and address all the concepts embodied in the negotiated standard offer. A-43 When should evidentiary hearings begin? Sorne parties, as discussed above, are extremely anxious for hearings to star almost immediately; the utilities would prefer a pause, in essence to catch their breath and gain some experience with the negoti- ated standard offer. While we are anxious to proceed with our continuing and evolving endeavor of valuing and pricing QF power, and establishing a lasting standard offer based on long-run avoided costs, we think it would be very useful for the parties to digest, evaluate, and reflect on what has been done thus far in preparing for hearings. Hearings, we believe, should start in early 1984, with another prehearing conference in December of 1983. The prehearing conference will be set by a separate notice. XII. EFFECTIVE DATE OF THIS OPINION AND ORDER We think that Standard Offer #4 and its three payment options, which are approved and adopted by this opinion and the following order, are a significant step toward valuing and pricing QF power over the long term. QFs have gained some more standard offer options, which can only help stimulate new projects and facilities. Given the consensus reached, we do not anticipate receiving applications for rehearing on this interim decision. Accordingly, we will make the following order effective the date of signature. We also do this because we think it is in the public interest to have Standard Offer #4, albeit a negotiated and interim standard offer, available for use as soon as possible. However, it is possible that applications for rehearing may be filed within the time period after the order’s effective date as set out in Public Utilities Code § 1731, and we expect utilities not to actually enter or sign contracts under Standard Offer #4 for at least 30 days after today, and until any such applications for rehearing, if they are filed, are acted on by us. We take this measure as a procedural safeguard, in fairness to all parties, in view of our acting without an evidentiary record upon which to make findings of fact sufficient to issue a decision to withstand judicial review. A-44 XIII. FINDINGS OF FACT AND CONCLUSION OF LAW Findings of Fact 1. D.83-05-038 announced a negotiating conference for these consolidated proceedings. That conference was publicly noticed, open to the public, and lasted from May 23 through June 24, 1983. 2. The amended applications in these proceedings, with the changes noted on the record during the second prehearing confer- ence, contain Standard Offer #4. That standard offer, and three payment options under it, are acceptable to the respective utili- ties, QFs, and staff, for interim use. Conclusion of Law The standard offers filed by the applicant utilities should be ratified for use by utilities and QFs in contractual power purchases, as authorized and restricted by the following order. INTERIM ORDER IT IS ORDERED that: 1. Standard Offer #4, Payment Options #1 through #3, as proposed by the Pacific Gas and Electric Company (PG&E), San Diego Gas and Electric Company (SDG&E), and Southern California Edison Company (Edison), shall be used by those utilities until further order of this Commission, but, in any event, for a minimum of six months and for a maximum of two years after the effective date of this order. However, in exercising those payment options under Standard Offer #4 the following restric- tions or conditions shall apply: a. Qualifying facilities (QFs) who are under a power purchase contract with a utility, either a contract under a standard offer or a nonstandard contract, shall not enter a contract based on Standard Offer #4 until their existing contract term is up. A-45 b. Only QFs who are not under contract and who have not completed their facility as of the effective date of this order may elect Payment Option #2. c. The “regulatory authority” clause in SDG&E’s and Edison’s Standard Offer #4 shall be eliminated. d. QFs who enter contracts under Standard Offer #4 will not be allowed to switch to a subsequent version of Standard Offer #4, or to other standard or nonstandard contracts, until the term of their contract is up. e. Payment Options #2 and #3 shall be extended and exercised by utilities for a maximum period of one year after the effective date of this order. f. The terms in Standard Offer #4, Options #4, Options #1, through #3, are subject to change and retroactive application in contracts signed by both parties after the effective date of a decision in A.82-03-26 et al., and depend- ing on the outcome in that proceeding, with respect to: 1. PG&E’s line loss factor. 2. Interconnection provisions involving future lines and system upgrades. 2 ='asurance. 4. Right to first refusal and right to purchase and abandonment. For contracts signed by both parties (QF and utility) prior to the effective date of a decision on the above terms in A.82-03-26 et al. the QF has the option of deciding to keep the terms as set forth in the signed contract if the QF notifies the utility of this decision in writing within 30 days after the effective date of the Commission decision on A.82-03-26. g. PG&E shall use a 15% discount rate for its levelized payment stream under Option #2. Any other ordered changes to Standard Offer #4 will be for prospective application only in new contracts. ee A-46 2. A QF which enters a contract under Standard Offer #4, as approved by this order, may not switch to another contract until the term of its Standard Offer #4 contract has expired or it has terminated; if a QF terminates early by breaching the contract the utility is under no obligation to enter a new contract or to purchase the QF’s power until: (1) minimum damages are paid if a minimum damages clause in the contract is applicable; or (2) if there is no applicable minimum damages clause, until foreseeable damages have been paid to the utility. The payment of minimal damages shall not discharge the breaching QF from ultimate payment of foreseeable damages caused by the breach. Utilities, on behalf of their ratepayers, shall vigorously pursue recovery of all foreseeable damages in the event of a QF breaching a power purchase contract. 3. Prices paid to QFs for power purchased under Standard Offer #4 provisions, and contracts as under any standard offer, will be recovered through the ECAC balancing account, and any collection the utilities make with respect to recovering for dam- ages or called on security shall be credited to that balancing account. However, utilities will be subject to ECAC ratemaking adjustment if it is demonstrated they did not diligently enforce all contract provisions. 4. Another prehearing conference shall be scheduled and held before evidentiary hearings begin. Its purpose will be to determine the order in which issues shall be addressed, dates for exchanging prepared testimony, and to set hearing dates. The issues that shall be addressed as early as possible in evidentiary hearings, and which we may address by another interim order, are: a. SDG&E’s forecast of energy production costs. b. Whether the levelized energy payment and the incre- mental energy rate payment options should be extended for Standard Offer #4 beyond the one year period as ordered above. 5S. PG&E, SDG&E, and Edison shall confer among them- selves and with our staff to devise uniform Standard Offer #4 contract language, except for the very few terms which must be utility specific due to different operating characteristics. They A-47 shall jointly submit their proposed uniform contract language as a compliance filing in these proceedings within six months from today (making the filing with the Docket Office and serving all appearances). Their proposed uniform contract language shall not be effective or used in contracts until it has been approved by this Commission. This order is effective today. Dated September 7, 1983, at San Francisco, California. I abstain. /s/ PRISCILLA C. GREW Commissioner LEONARD M. GRIMES, JR. President VICTOR CALVO DONALD VIAL Commissioners Commissioner William T. Bagley, being necessarily absent, did not participate. A-48 APPENDIX A Page | List of Appearances Applicants: Larry C. Mount, Attorney at Law, for Southern California Edison Company; Wayne P. Sakarias, John R. Asmus, Jr., and Vincent D. Bartolomucci, Attorneys at Law, for San Diego Gas & Electric Company; and Charles W. Thissell and Jo Ann Shaffer, Attorneys at Law, for Pacific Gas and Electric Company. Interested Parties: Roy Alper, Attorney at Law, for Indepen- dent Power Corporation; Chickering & Gregory, by C. Hayden Ames, Attorney at Law, for Geothermal Generation, Inc.; Pills- bury, Madison & Sutro, by Michael R. Barr, Attorney at Law, for Pillsbury, Madison & Sutro; Hanna & Morton, by R. Lee Roberts, Attorney at Law, and Henwood Associates, Inc., by David Branchcomb, for Ultra Systems, Inc., and Occidental Geother- mal, Inc.; Donald C. Davis, for Herzog Contracting Corporation; Nicole A. Clay, for San Diego Energy Recovery Project (SANDER); Frank F. Duquette, for McDonnell Douglas; Joseph Egan, for University Energy; Paul H. Eichenberger, for SAI Engineers, Inc.; Mark R. Farman, for Resource Management International, Inc.; Michel Peter Florio, Attorney at Law, Jon Elliott, and Sylvia Siegel, for Toward Utility Rate Normalization (TURN); Lee Freeman, Douglas Porter, and Jon Castor, Attor- neys at Law, for Pacific Lighting Energy Systems; Janice G. Hamrin, and Dan Richard, Attorney at Law, for Independent Energy Producers Association; Richard C. Hill, for Tosco Corpo- ration; Nossaman, Guthner, Knox & Elliott, by Peter C. Hoffman, Attorney at Law, for Applied Power Technology, Inc.; Neal A. Johnson, for California Solid Waste Management Board; Jim Kaiser, for Sierra Energy and Risk Assessment; Laura B. King, for Natural Resource Defense Council; Jane S. Kumin, for Natomas Company; C. M. Laffoon, for Geothermal Generators, Inc.; Mark Lyons, Attorney at Law (New York, Washington, D.C.), for Ultra Systems, Inc.; P. R. Mann & Associates, by Philip R. Mann, Attorney at Law, for California Manufacturers Association; William B. Marcus, for California Hydro Systems, Inc.; Kenneth R. Meyer, for Energy Consulting Group; Martin C. A-49 Recchuite and Michael J. Myers, Attorney at Law, for ARCO Solar, Inc.; Brown, Vence & Associates, by Tom Reilly, for Brown, Vence & Associates; Donn Ruotolo, for Ebasco Services, Inc.; James Samis, for Thermonetics, Inc.; Gary D. Simon, for Sigma Group; Graham & James, by James D. Squeri, Attorney at Law, for Union Oil Company of California; Messrs. Downey, Brand, Seymour & Rohwer, by Philip A. Siohn, Attorney at Law, for Federal Paper Board, Inc., and Sutherland, Asbill and Bren- nan, Attorneys at Law; William E. Swanson and Jasper Williams, Attorney at Law, for Stanford University; Randall M. Tinkerman, for American Energy Projects, Inc.; Frederick S. Waiss, Attorney at Law, for Stauffer Chemical Company; Gregg Wheatland and Kathy Weinheimer, Attorneys at Law, for Cali- fornia Energy Commission; Cooper Engineers, by Mark White, for West County Agency; Harry Winters, for University of Cali- fornia; Matthew J. Wristbridge, Attorney at Law, for General Electric Company; Donald G. Salow, for Stone & Webster, Margaret E. Rueger, for U. S. Windpower, Inc.; and Reed V. Schmidt and Norman Ross Burgess, for themselves. Commission Staff: Brian T. Cragg, Attorney at Law, and John D. Quinley. (END OF APPENDIX A) A-50 APPENDIX C Decision 83-12-050 December 20, 1983 Before the Public Utilities Commission of the State of California Application 82-04-44 (Filed April 21, 1982; amended April 28, 1982, July 19, 1982, July 11, 1983, and August 2, 1983) Application 82-04-46 (Filed April 21, 1982; amended May 12, 1982, July 11, 1983, and August 10, 1983) Application 82-04-47 (Filed April 21, 1982; amended July 11 and August 2, 1983) Second Application of Pacific Gas and Electric Company for Approval of Certain Standard Offers Pursuant to Decision No. 82-01-103 in Order Instituting Rulemaking No. 2. And Related Matters. (See Decision 83-09-054 for Appearances. ) OPINION ON PETITIONS FOR MODIFICATION OF DECISION 83-09-054 On September 7, 1983 we issued Decisicn (D.) 83-09-054, which was an interim decision, adopting three payment options for Standard Offer No. 4. These options are to be used by the three applicant utilities in these consolidated proceedings. Our decision followed after a five-week negotiating conference and, subsequentl;, a prehearing conference lasting two days. Petitions for modification were filed by the Independent Energy Producers (IEP) and Occidental Geothermal, Inc. (Occidental); a response to both petitions was filed by Southern California Edison Company (Edison), and [EP responded to Occidental’s petition. A-51 Occidental’s Petition Occidental points out that our D.83-09-054 directed the utili- ties to delete the regulatory authority clause, but that Edison’s contract contains another clause, termed the “amendment clause” which Occidental thinks could have substantially the same effect as the regulatory authority clause that was deleted. We ordered the regulatory authority clause deleted to afford qualifying facilities (QF) the certainty and sanctity of contract terms and fixed term prices they wanted, but in exchange we did not allow subsequent contract switching. The regulatory authority clause, of course, could have allowed us to essentially change contract terms retroactively. Edison’s response is that although the “amendment clause” would apply only if both Edison and the QF agreed that there was a “change in circumstances” necessitat- ing a change in the contract terms, it does not object to removing the clause if keeping it in the contract alarms QFs. We will direct Edison to remove the amendment clause from its Standard Offer No. 4. The second point raised by Occidental is that Edison’s Stan- dard Offer No. 4 is not clear that after the fixed price term or prior to the time of firm delivery, the QF will receive energy payments based on Edison’s full avoided operating cost as deter- mined now for Standard Offer No. 2 (for firm delivery based on short-run avoided cost). Edison’s response on this point is essen- tially that it did not mean to build any ambiguity into the contract. It agrees to change the relevant contract provisions by inserting the language underlined below (see Attachment A-7 to Edison’s response): Seller shall be paid 2 Monthly Energy Payment for Energy delivered by Seller and purchased by Edison at a rate equal to 100% of Edison’s published avoided cost of energy based on Edison’s full avoided operating cost as updated periodi- cally and accepted by the Commission. We think the amended contract language proposed by Edison in its response to Occidental’s petition is clear enough. Occiden- tal’s expressed fear is that a future Commission may decide that QFs should be paid 80% of utilities’ full operating costs, and that, A-52 instead of 100%, only 80% wouid be paid by Edison. With Edison’s proposed amendment all the Standard Offer No. 4 contracts refer to “full avoided operating cost.” Because the fixed term is 10 years, it is extremely difficult to estimate what short- run avoided costs will be after that period. But it is clear QFs - under Standard Offer-No. 4 contracts will receive 100% of full avoided cost as those costs are then determined and accepted by this Commission. That is all the certainty contemplated at the negotiating conference, and it is all the certainty we can extend at this time. Furthermore, on November 16, 1983, Occidental responded to Edison’s response by applauding “Edison’s good faith in making these important modifications.” Occidental therefore seeks to withdraw its petition. IEP, similarly seeks dismissal of that portion of its petition supporting Occidental’s petition. We will direct Edison to amend its contract language as proposed. No further amendment is necessary or appropriate. IEP’s Petition IEP, in addition to supporting the points addressed by Occiden- tal, takes exception to the procedure we set out in D.83-09-054 to initiate the process of having a standardized Standard Offer No. 4. We ordered the three utilities and our staff to work together to develop standard contract language, with the resulting proposed contract to be reviewed in subsequent hearings. While pleased with our effort for more standardization, IEP thinks QFs will be unfairly prejudiced by not being part of all meetings on the subject between the utilities and our staff. We adopted the procedure because we thought it could expe- dite at least getting a work product for the many and various QF interests that are parties to these proceedings to review and react to. We thought the initial logistics fo- the undertaking, which is a complex task, would be more expedient: The many QF represent- atives will have full opportunity to review the work product filed by the utilities. Rather than modify the procedure, we suggest that our staff arrange an informal meeting with the utilities and QFs shortly after the utilities file the proposed standard language, which will be served on all parties. Thereafter, any remaining Nees A-53 concerns and issues can be more succinctly addressed during hearings. We will not modify the procedure as requested by IEP. We will, however, order the utilities to file the standard contract language six months from today. Conclusion Standard Offer No. 4, along with the energy price, incremental energy rate and shortage value forecasts adopted by D.83-09-054 has become effective. New incremental energy rates and/or avoided capacity cost values that may be adopted by the Commis- sion in general rate case or ECAC proceedings will not affect the price forecasts established over the fixed payment term under Standard Offer No. 4, until further orders are issued in this proceeding. No applications for rehearing were filed after D.83-09-054 was issued. We trust there will be no further petitions for modification of that decision, as parties should raise any concerns or proposals relating to Standard Offer No. 4 at the upcoming evidentiary hearing. We will be very reluctant to indulge any petitions that may address or propose piecemeal changes to existing Standard Offer No. 4, because it is being relied on by QFs and utilities alike. Efforts for ex parte modification only cloud an overall endeavor to bring some clarity and certainty so that the QF industry can analyze the standard offers available and make its choices. Procedurally, the next step for parties interested in this standard offer, and any changes for prospective application is to raise these points in the evidentiary hearings. Findings of Fact 1. The modifications Edison proposes for its Standard Offer No. 4 contract, contained in its response to IEP’s and Occiden- tal’s petition, are reasonable and should be adopted. 2. QFs are not unduly prejudiced or denied due process by the procedure D.83-09-054 established to have uniform standard contract language proposed. A-54 Conclusions of Law 1. The petition for modification filed by Occidental should be granted, while IEP’s petition should be granted in part and denied in part in accordance with our findings in this order. 2. The following order should be effective today to bring certainty quickly and enable QFs and others to expeditiously evaluate contract options. ORDER IT IS ORDERED that: 1. Southern California Edison Company (Edison) shall amend its Standard Offer No. 4 as it proposes in its response to the petitions for modification filed by the Independent Energy Producers (IEP) and Occidental Geothermal, Inc. (Occidental). 2. The petition for modification of Occidental is granted with respect to Edison’s removing the “amendment clause” of its Standard Offer No. 4 contract, and it is granted to the extent of Edison’s proposed modifications with respect to the energy price to be paid either before firm production or after the fixed price term. 3. IEP’s petition for modification is granted with respect to Edison’s being ordered to delete its amendment clause, but denied concerning its proposed modification of the procedure in Ordering Paragraph 5 of D.83-09-054. 4. The compliance filing ordered by Ordering Paragraph 5 of D.83-09-054 shall be filed no later than six months from today. A-55 This order is effective today. Dated December 20, 1983, at San Francisco, California. I abstain because of reportable financial interest in potential small power producers. /s/ PRISCILLA C. GREW Commissioner LEONARD M. GRIMES, JR. President VICTOR CALVO DONALD VIAL WILLIAM T. BAGLEY Commissioners ee A-56 APPENDIX D Decision 84-08-035 August |, 1984 Before the Public Utilities Commission of the State of California Application 82-04-44 (Filed April 21, 1982; amended April 28, 1982, July 19, 1982, July 11, 1983 and August 2, 1983) Application 82-04-46 (Filed April 21, 1982; amended May 12, 1982, July 11, 1983, and August 10, 1983) Application 82-04-47 (Filed April 21, 1982; amended Juiy 11, 1983 and August 2, 1983) Second Application of PACIFIC GAS AND ELECTRIC COMPANY for Approval of Certain Standard Offers Pursuant to Decision No. 82-01-103 in Order instituting Rulemaking No. 2. And Related Matters. OPINION MODIFYING DECISION 83-09-054 By Ordering Paragraph | of Decision (D.) 83-09-054, this Commission ordered that “Standard Offer No. 4, Payment Op- tions Nos. | through 3, as proposed by Pacific Gas and Electric Company (PG&E), San Diego Gas & Electric Company (SDG&E), and Southern California Edison Company (Edison) shall be used by those utilities until further order of this Commis- sion, but, in any event, for a minimum of six months and for a maximum of two years after the effective date of this order.” With respect to Payment Options Nos. 2 and 3, the utilities were to exercise these options for a maximum period of one year after the effective date of the order. Because D.83-09-054 became A-57 effective on September 7, 1983, these payment options are due to expire on September 7, 1984. Standard Offer No. 4 was the result of a negotiating conference held during the summer of 1983. The goal of the negotiating conference was to develop an interim Standard Offer No. 4 which the parties “could comfortably tolerate and work under while refinement and ‘perfection’ could be pursued in subsequent evi- dentiary hearings.” (D.83-09-054, at p. 8.) By Administrative Law Judge’s (ALJ) Rulings issued during 1984, the procedure to be followed in these “subsequent eviden- tiary hearings” was established. The proceeding has been divided into two phases—Phase I which will focus on the appropriate costing methodology for Standard Offer No. 4 and Phase II which will examine the prices based on the adopted methodology, appropriate price approaches, and all other terms of Standard Offer No. 4. Hearings for Phase I began on July 23, 1984. On May 7, 1984, the Commission staff filed a “Recommenda- tion of the Commission Staff to Establish Procedures for Phase I of the Long-Run Offer Hearings.” Among other things, the staff observed that because Phase I was limited to an examination of costing methodologies, it would be appropriate to defer issues related to payment options until Phase II as directed by the ALJ. Under these circumstances, it is the staffs opinion that energy Payment Options Nos. 1, 2, and 3 and the energy price forecasts adopted in D.83-09-054 be extended until the conclusion of Phase II. The staff asserts that this approach will preserve the status quo, enabling qualifying facilities (QFs) to have the benefit of energy price certainty and eliminating any need to analyze and adopt incremental energy rates prior to Phase II. During the prehearing conference of May 9, 1984, the staff reiterated these recommendations. While there were no objec- tions to the recommendations, at least one party requested that the incremental energy rate to be paid the QF by PG&E under Option No. 3 be based on the incremental energy rate approved in PG&E’s most recent general rate case. On June 15, 1984, Independent energy Producers (IEP) filed a motion for a revised procedural schedule for the Standard Offer A-58 No. 4 proceeding. Specifically, IEP requests that (1) interim Standard Offer No. 4, Payment Options 1, 2, and 3 be continued through the end of 1986 or until the issuance of a final decision in this proceeding; (2) hearings on the “costing methodology” be commenced as scheduled by the ALJ; (3) hearings on a revised incremental energy rate be commenced no later than Octover 1984; and (4) hearings “‘on the broader assumptions and terms of a final Standard Offer No. 4” be commenced after the Commis- sion issues its decisions on costing methodology and an interim incremental energy rate pricing option. According to IEP, the incremental energy rate used for purposes of interim Standard Offer No. 4 is not a viable option for gas-cogenerated QFs. IEP’s motion is supported by the Independent Power Corpora- tion (IPC). IPC further asks that PG&E’s SDG&E’s and SCE’s interim Standard Offer No. 4 incremental energy rates be modi- fied to reflect information developed in their most recent general rate cases. WE have reviewed these comments and concur with the staff, IEP, and IPC regarding the extension of negotiated Standard Offer No. 4. At the time we issued D.83-09-054 we contemplated that the issues related to the payment options would have been explored in evidentiary hearings prior to the expiration date set for Payment Options Nos. 2 and 3. In fact, we optimistically forecast the conclusion of these hearings as early as six months from the issuance of D.83-09-054. Unfortunately, only hearings on Phase | of this proceeding will be concluded prior to September of this year, with Phase II commencing after that time. Under these circumstances, and given the general acceptance of interim Standard Offer No. 4, we will extend the effective date of the terms of that offer, including Payment Options Nos. 1, 2, and 3, and the energy price forecasts adopted in D.83-09-054. This extension, which applies to all terms of the offer, will be effective until further order of this Commission. We will not, however, amend Payment Option No. 3 in any way. That payment option was part of the negotiated package which the Commission approved on D.83-09-054. A change in one term would require the reexamination of all other terms of the A-59 standard offer. We prefer to maintain the status quo and adopt modifications to Standard Offer No. 4 following the evidentiary hearings now scheduled in this proceeding. We also note that a QF who finds the terms of interim Standard Offer No. 4 unac- ceptable may in fact negotiate a separate contract. Despite some QFs dissatisfaction with that remedy, we have made clear in previous decisions that all utilities are to negotiate with QFs in good faith. With respect to the requests for October hearings on the utilities’ incremental energy rates, we are unable to commit our limited resources to such hearing dates at this time. At the most, we can reiterate that hearings on Phase I began on July 23, 1984. Upon completion of that phase, the Commission will make a determination either in its decision in Phase I or by ALJ Ruling whether to segregate the issue of incremental energy rate valua- tion and hear the matter prior to Phase II hearings. Findings of Fact 1. A reasonable modification of D.83-09-054 has been re- quested by the Commission staff, IEP, and IPC to extend the effective date of interim Standard Offer No. 4. 2. The other requested modifications of the Standard Offer No. 4 procedural schedule cannot be adopted at this time. Conclusions of Law 1. The terms of interim Standard Offer No. 4 approved in D.83-09-054 should be extended until further order of this Commission. 2. The motion of IEP should be denied, except to the extent granted in keeping with Conclusion of Law 1. 3. To ensure the extension of Standard Offer No. 4 before it would otherwise expire, this order should be made effective today. A-60 ORDER IT IS ORDERED that: 1. All terms and conditions of interim Standard Offer No. 4 adopted in D.83-09-054 shall be extended until further order of this Commission. 2. The motion of Independent Energy Producers, except to the extent granted by Ordering Paragraph 1, is denied. This order is effective today. Dated August 1, 1984, at San Francisco, California. LEONARD M. GRIMES, JR. President VICTOR CALVO DONALD VIAL Commissioners Commissioner Priscilla C. Grew, be- ing necessarily absent, did not participate. Commissioner William T. Bagley, being necessarily absent, did not participate. A-61 APPENDIX E Decision 85-04-075 April 17, 1985 Before the Public Utilities Commission of the State of California Application 82-04-44 (Filed April 21, 1982; amended April 28, 1982, July 19, 1982, July 11, 1983 and August 2, 1983) Application 82-04-46 (Filed April 21, 1982; amended May 12, 1982, July 11, 1983, and August 10, 1983) Application 82-04-47 (Filed April 21, 1982; amended July 11, 1983 and August 2, 1983 Second Application of PACIFIC GAS AND ELECTRIC COMPANY for Approval of Certain Standard Offers Pursuant to Decision No. 82-01-103 in Order Ins ituting Rulemaking No. 2 And Related Matters. INTERIM OPINION I. Summary This decision continues the suspension of Payment Option No. 3 of interim Standard Offer (SO) 4 for Qualifying Facility (QF) projects over 50 megawatts (MW), which had been ordered earlier for Pacific Gas and Electric Company (PG&E) and Southern California Edison (SCE). It also extends the suspen- sion for projects over 50 MW to Payment Option No. 3 of interim SO 4 for San Diego Gas and Electric Company (SDG&E). It presents two options for comment regarding continued availability and terms of all of Payment Option No. | and Payment Option No. 2, and of Payment Option No. 3 for projects less than 50 MW, prior to availability of a final long-run standard offer. In assessing whether the existing standard offers continue to provide a reasonable protection for ratepayers, we have relied primarily on the utility filings of the results of project information questionnaires sent to QFs as part of our adopted Interconnection Priority Procedure (IPP), and on the information contained in A-62 the utilities’ most recent Quarterly Status Reports (QSRs) con- taining data current through the end of 1984. We conclude that the capacity payments in the interim SO 4 and the energy payments in Payment Option No. | and Payment Option No. 2 of the interim SO 4 would over-value additional QF projects not already under contract to the utilities. This is true for all sizes of QF projects and for SDG&E as well as for PG&E and SCE. The Public Staff has recommended an immediate suspension of all payment options of interim SO 4 for PG&E and SCE until a final SO 4 is available, unless prices are adjusted to reflect current conditions. We agree with Public Staff that further study is needed of the implications of large cogeneration projects over 50 MW for utility resource planning purposes. Because of the poten- tially large impact of such projects on system avoided costs, [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385019_0699%3A2. Public record. Not legal advice.