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Decision No. 96-12-028, Investigation No. 89-07-004 December 9, 1996 Order Instituting Investigation on the Commission's INTERIM OPINION REPLACING THE INDEX METHODOLOGY FOR CALCULATING AVOIDED ENERGY COSTS
1. Summary In this decision, we replace the avoided cost index methodology for calculating avoided energy costs, which was adopted in Decision (D.) 91-10-039, to conform with the criteria established by Assembly Bill (AB) 1890, (Stats. 1996, Ch. 854), signed by Governor Wilson on September 23, 1996. This legislation is consistent with our general direction in this proceeding, in which we have expressed the need to replace the index methodology because it does not adequately reflect the marketplace and it is administratively burdensome. We adopt an interim formula for each utility consistent with the requirements of AB 1890, which adds Section 390 to the Public Utilities (PU) Code. In our Preferred Policy Decision in electric restructuring (D.95-12-063, as modified by D.96-01-009), we established that the Short Run Avoided Cost (SRAC) price would be based on the clearing price of the Power Exchange, once that entity is deemed to be functioning properly. Section [*2] 390 provides guidance regarding this pricing mechanism. Future implementation issues will be considered in subsequent phases of our restructuring rulemaking and investigation (Rulemaking (R.) 94-04-031/Investigation (I.) 94-04-032) . Our goals in this proceeding have been twofold: (1) to rely on market-determined prices that reflect the utilities' avoided gas purchases in a manner that is consistent with the definition of avoided costs, as previously prescribed by this Commission and (2) to adopt a methodology that minimizes the regulatory oversight function and burden. These goals were articulated in Assigned Commissioner's Rulings (ACR) issued on September 20, 1995 and March 22, 1996. We affirm the ACRs at this time. The enactment of AB 1890 into law has overtaken this proceeding.
2. Background Pursuant to the federal Public Utility Regulatory Policies Act of 1978 (PURPA), electric utilities are required to purchase electricity from certain power producers known as qualifying facilities (QFs) . Some of these purchases are priced according to short-run avoided cost principles and prices consist of both a capacity and energy component. Each electric utility posts monthly [*3] energy prices intended to represent the utility's own avoided costs for the coming month. The monthly posting determines energy payments from utilities to QFs priced at the purchasing utility's short-run avoided costs. Today's decision replaces the methodology for determining the energy rate component, or the amount per kilowatt hour which a QF is paid for energy delivered, of the monthly postings. The energy rate has consisted of three elements: the Incremental Energy Rate (IER), the utility electric generation (UEG) gas rate, and various adders, in particular the variable operations and maintenance (O&M) adder. The IER is a measure of thermal efficiency and is derived from the incremental amount of energy that a utility would use to generate the amount of power supplied by QFs. IERs are determined in each electric utility's Energy Cost Adjustment Clause (ECAC) proceeding, and generally tend to be litigious. The UEG gas rate is the natural gas rate charged to each electric utility's power plants that use natural gas fuel. Adders are intended to compensate QFs for savings the electric utilities realize by purchasing QF energy, and are added to the product of the gas rate and the [*4] IER rate. The index methodology has been used as a proxy for the gas rate. In a series of decisions beginning with D.91109, issued in 1979, the Commission established a methodology for the electric utilities to follow in making the monthly posting. When the fuel on the margin was natural gas, the utility was to apply to the calculation its weighted average cost of gas (WACOG). If it included noncore gas in its UEG supplies, then the utility was to use the noncore WACOG for that portion. In D.91-10-039, the Commission adopted an interim methodology designed to replace the noncore WACOG. n1 The noncore WACOG represented a bundled commodity and transportation price at the California border (or local distribution company city-gate) and the adopted methodology was intended to serve as a proxy for that price.
The index methodology represented a price for buying the commodity to which is added the utility's forecast cost of transportation to the California border. The index methodology prices gas purchased at a known supply basin at the weighted average cost of gas in that basin (according to indices derived from trade publications) plus the full tariffed cost of firm transportation to the California border.
In D.91-10-039, we stated our intent to adhere to the adopted index methodology until a broader examination of pricing methodologies could occur, unless annual reports submitted by the utilities indicated large differences in the results. While the annual comparison reports have not demonstrated significant differences in the results, parties have proposed various modifications to the index methodology to accommodate certain aspects of gas industry restructuring, which were not contemplated when the methodology was adopted. The evolution of the gas market has raised issues related to capacity brokering and new supply and transportation options, such as customer-specific discounts, intrastate transportation discounts, and reservation surcharges on third-party shipper volumes. Because [*6] the index methodology does not explicitly provide a method for incorporating such market changes, many of these issues have led to protests of the utilities' monthly postings. 3. Procedural History Pursuant to D.91-10-039, Southern California Edison Company (SCE) and Pacific Gas and Electric Company (PG&E) have filed annual reports which compare gas costs under the adopted index methodology and the recorded cost methodology. n2 In response to the 1993 filings, the Commission received comments on March 15, 1993 and reply comments on April 5, 1993 in which parties proposed various modifications which they believe may result in a more market-sensitive index mechanism. n3 The assigned administrative law judge (ALJ) issued a ruling on April 30, 1993, which defined the scope of the index methodology review. In particular, the ruling confirmed that there was to be no re-examination of the foundation and underpinnings of the methodology at that time.
Parties continued to negotiate on refinements to the index methodology and appropriate procedures to incorporate flexibility into the methodology, but were unsuccessful in resolving outstanding issues. A prehearing conference (PHC) was held on October 7, 1993. No party at the PHC indicated disputed factual issues for which a hearing would be necessary. Opening comments were filed on December 9, 1993 and reply comments were filed on January 10, 1994. A roundtable/oral argument discussion was held on March 9, 1995 for the purpose of clarifying each party's position and addressing the ALJ's questions. Limited comments were accepted on storage issues and gas exchange credits. Comments on these issues were filed on March 31, 1995 and reply comments were filed on April 10, 1995. Because of the technical nature of the issues, on July 28, 1995, the assigned ALJ's proposed decision was issued for comment prior to consideration by the Commission. On the same date, Commissioner Fessler issued an alternate proposed decision in this proceeding. On September 18, 1995, both proposed decisions were withdrawn from the Commission's Agenda. By ACR issued on September 20, 1995, submission in this case [*8] was set aside and the record was reopened to more fully consider SRAC reform. Consistent with the guidelines of that ruling, by October 20, 1995, parties were to file and serve proposed market-based avoided cost pricing mechanisms which are administratively streamlined, prospective, transparent, and verifiable. This deadline was extended several times because parties represented that serious negotiations were ensuing. On February 16, 1996, comments on and proposals for SRAC reform were received from PG&E, SDG&E, jointly from SCE, CCC, and IEP (collectively, the Joint Parties I), CAC, Watson, ORA, the Zond Corporation (Zond), the Energy Finance Forum (Forum), and jointly from the California Energy Company (CalEnergy), the Geothermal Energy Association (GEA), and the Center for Energy Efficiency and Renewable Technologies (CEERT) (collectively, the Joint Renewable Parties). On March 22, 1996, a second ACR (ACR II) was issued which provided procedural guidance regarding the scope of subsequent portions of this proceeding, allowed for one round of reply comments based on this narrowed scope, and provided notice for technical workshops to be held on April 16 and 17, 1996, facilitated [*9] by the Commission Advisory and Compliance Division (CACD) (now the Energy Division). Reply comments were received on April 10, 1996, and were filed by PG&E, SDG&E, the Joint Parties I, CCC and IEP jointly, Watson, CAC, the Forum, and the Joint Renewable Parties (to which Zond and the Oxbow Corporation have joined). After the workshops, the Energy Division submitted a draft report for comment and a final report was filed on May 8, 1996. On June 25, 1996, PG&E submitted supplemental comments on the final workshop report which represented agreements forged between PG&E, IEP, CCC, and CAC (Joint Parties II). On November 15, 1996, SDG&E and CCC filed a joint motion for adoption of a settlement agreement in connection with the interim SRAC formula addressed in @ 390. Comments were filed by ORA and the CAC, and jointly by PG&E and SCE. We will use the record provided by this latter set of proposals and comments to address the criteria required for compliance with @ 390. Section 390(b) addresses SRAC pricing for the transition period until SRAC prices can be based on the clearing price of the Power Exchange:
(b) Until the requirements of subdivision (c) have been satisfied, short run [*10] avoided cost energy payments paid to nonutility power generators by an electrical corporation shall be based on a formula that reflects a starting energy price, adjusted monthly to reflect changes in a starting gas index price in relation to an average of current California natural gas border price indices. The starting energy price shall be based on 12-month averages of recent, pre-January 1, 1996, short-run avoided energy prices paid by each public utility electrical corporation to nonutility power generators. The starting gas index price shall be established as an average of index gas prices for the same annual periods.
4. Positions of the Parties Prior to the passage of this legislation, discussions and negotiations among the parties resulted in several different proposals for market-based treatment of SRAC that each proponent believes could be implemented in a very simple fashion. We summarize these proposals briefly here. 4.1 Formulaic Proposals The Joint Parties I, the Joint Parties II, Watson, and CAC each proposed a formulaic approach to interim SRAC pricing. These formulas are identical in concept. Each formula is designed to rely upon a base or [*11] starting energy rate. Each formula recognizes market realities by using a simple average of gas market indices: each formula establishes a base escalation price based upon those gas indices, determines the monthly percentage change in the base escalation price by using an average of monthly published index prices at the California border, and applies the percentage change to adjust the monthly base energy price. Finally, each formula employs a factor, applied to the resultant energy price, to reflect an escalation of that portion of the price that is dependent on variable or escalating gas costs. This variable component is then adjusted monthly based on a percentage change of the simple average of specific market price indices for natural gas. For these purposes, the Joint Parties I have proposed that the indices are those published in BtU Weekly, Natural Gas Week, and Natural Gas Intelligence. The Joint Parties II's interim formula indexes PG&E's SRAC energy price to published natural gas prices at the California border based on the simple average of Malin and Topock border prices, as published in Natural Gas Week, Natural Gas Intelligence, and Gas Daily. As proposed, [*12] the transition formula would replace the current annual determination of setting the IER and O&M adder as well as the methodology for determining the avoided cost of gas. 4.2 SDG&E's Proposal SDG&E agrees with the move towards market-based pricing; however, SDG&E planned to submit a separate application to develop interim SRAC reform. SDG&E indicates that its proposal will also eliminate the use of the IER and O&M adder. Until that application is submitted and approved, SDG&E proposed to continue paying QFs using its tariff-based index methodology, as established in D.90-09-089 and D.91-10-039. In its reply comments, SDG&E asserts that the formula proposals should not be applied to SDG&E's determination of SRAC, as IEP and CCC suggest. SDG&E believes that the formula proposals will not benefit and may harm SDG&E's ratepayers. 4.3 ORA's Proposal ORA recommends that SRAC energy prices be a weighted average of the IER (augmented by gas prices and adders) and certain current electric market indices. ORA recommends that the gas prices be derived using the average border price index methodology, as proposed by SCE in its January, 1993 comments. The O&M adders should [*13] reflect the latest values adopted in the next ECAC proceedings for PG&E, SCE, and SDG&E. In reply comments, ORA states its concern that adopting a formulaic approach would freeze the currently adopted SRAC values for the duration of the transition time period until the Power Exchange is fully functional. ORA therefore believes that such an approach preserves the status quo, precludes a review of the O&M adder methodology, and freezes existing values in an era of potential divestitures of electric generation resources that may produce a major change in SRAC prices. 4.4 Renewable Parties' Proposals The Joint Renewable Parties assert that any alternative approaches to setting SRAC prices should be adopted so that the utilities' full avoided cost, as defined in PURPA, is reflected in the SRAC energy payments. The Renewable Parties believe that today's SRAC prices are artificially low and will skew competition; therefore, the manner in which avoided costs are treated during the transition to a competitive market is critical. To this end, they propose two general approaches:
1. a formulaic approach that would tie SRAC to objective, publicly available indices, such as gas [*14] prices or the incremental pricing formula adopted for the San Onofre Nuclear Generating Station (SONGS), with different formulae available to reflect the characteristics of QF suppliers utilizing different fuel sources and technologies; and 2. a proxy approach that would tie avoided cost to the costs of proposed utility plants that would have been incurred but for the QFs. The Energy Finance Forum is an affiliation of financial institutions who provide debt, equity, and other financial instruments to the electric power industry. The Forum believes that SRAC energy payments should reflect the actual fuel, operation and maintenance, and related costs avoided by utilities as a result of purchases from QFs. The Energy Finance Forum supports simplification of the SRAC determination in principle, but not if the reduction of payment levels is an end in and of itself. The Forum believes that the determination of SRAC energy payments may be undervalued and should be reconsidered. Zond agrees that determination of the SRAC energy payments should be streamlined, since use of the index methodology and the IER and O&M adder make these determinations far too contentious and requires substantial [*15] resources of both the Commission and the parties. Zond believes that the Commission must be mindful of the importance of providing for equal market access for all market participants and points out that renewable QFs provide similar benefits to nuclear power plants in terms of reduced emissions. Zond recommends that the Commission replace the entire SRAC methodology rather than tackle it on a piecemeal basis. In addition, like the Joint Renewable Parties, Zond recommends that any new methodology for determining SRAC payments must result in an approximation of the purchasing utility's full avoided costs, as defined in PURPA and in FERC's and this Commission's decisions implementing PURPA. 5. Discussion We are very interested in moving from an administratively determined avoided cost price towards one based on market pricing. The index methodology has moved us along that continuum, but implementation of that methodology has been fraught with contention. Protests have been filed since the index methodology has been implemented. (See, for example, D.92-03-022, D.92-08-040, D.93-01-040, D.93-10-071, D.94-04-040, D.95-01-003, and D.95-09-117.) Parties themselves have expressed [*16] frustration with the administrative determination of these costs. As the gas market has evolved, changes in the gas market, including capacity brokering and new supply and transportation options, present new market realities that are not adequately reflected in the avoided cost index methodology. PU Code @ 390 moves us to market-based pricing for the long-term and provides an interim formulaic approach for the transition period. We must evaluate the parties' proposals according to these new requirements, in order to fully comply with the law. 5.1 Evaluation of Proposals The formulaic proposals have several components in common, the most significant of which is that each formula pegs the variable component of the starting prices to monthly adjustments based on simple averages of specific market price indices, as published in various trade publications. These border price calculations are based on robust, published indices that reflect changes in market conditions; therefore, these formulas meet our goal of market-based pricing, as required by @ 390. The proposals made by ORA and the Renewable Parties do not meet the criteria established by @ 390. ORA's proposal is based [*17] on electric indices, which ORA admits are not currently available as prospective measures. ORA believes this problem could be solved by assigning retrospective indices a low weighting, although ORA also admits such indices do not reflect robust markets. In the absence of the legislation, this methodology may have provided ratepayer savings. The proposals put forward by the Renewable Parties do not comply with the straightforward requirements of @ 390. These proposals go far beyond the definition of avoided cost, as currently applied. Determining the full costs and benefits of such factors as environmental gains, financial savings, and distributed generation is far from straightforward. While these parties are convinced that a full examination of the proper definition of full avoided costs is necessary, such an examination is beyond the scope of the statute and unnecessary in the long run given industry restructuring. 5.2 Adopted Formulas for SCE, PG&E and SDG&E The Joint Parties I, Joint Parties II, CAC, and Watson propose the same basic formula, with different approaches to determining the specific parameters of the formula. Once the starting SRAC price is determined, [*18] it is adjusted monthly. In general, the parties who support this approach do not substantively disagree on which indices should be used or how each should be weighted. The contentious issues remaining to be determined are the derivation of a base energy price and a base gas price to be used in the formulas. Section 390 provides guidance in these areas. Watson and the Joint Parties I propose to use the same set of California border price indices for SCE: both formulas use the average of the California/Arizona (Topock) border prices reported in Natural Gas Week, Natural Gas Intelligence, and BtU Weekly. Parties to this proceeding have tracked this set of border price indices for over three years and agree that these indices are robust and generally reflective of market dynamics. SCE and several QF parties have filed an agreement to use this set of border indices to resolve the outstanding protest issue concerning SCE's past posting of gas purchases made at the California border. n4 From this filing, it is clear that CAC agrees that these are the correct indices to utilize. It is reasonable to adopt this set of indices for purposes of deriving SCE's formula.
n4 This agreement was filed on April 30, 1996 in I.89-07-004 as a Joint Motion by Watson, CCC, and the CAC. By this motion, Watson, CCC, and CAC moved to withdraw their respective continuing protests to SCE's pricing of gas purchases at the Southern California border as reflected in SCE's monthly avoided cost postings since June 1992. This is made in conjunction with an attached agreement, signed by the above parties and SCE, that "in months when SCE forecasts purchases at the Southern California border, Edison will post the price for these purchases utilizing an average of three published Southern California border bidweek gas price indices -- Natural Gas Intelligence, Natural Gas Week, and BtU Weekly." The joint motion was approved in D.96-07-023. [*19] For PG&E, a different set of border indices is appropriate, given the mix of Canadian and Southwest supplies that serve northern California. Watson recommends a simple average of the published border prices at both Malin, Oregon and Topock, Arizona. The Topock border price index employs the same set of publications discussed above. The Malin border price index is the same Malin index that PG&E has used in its postings, i.e., the average of the published Malin prices from Natural Gas Week, Natural Gas Intelligence, and Gas Daily. The Joint Parties II recommend that a simple average of Malin and Topock border prices be used, as published in Natural Gas Week, Natural Gas Intelligence, and Gas Daily. We will adopt the Joint Parties II recommendations for PG&E. Time differentiation (i.e., the time-of-use (TOU) pricing indicators for peak and off-peak delivery of energy) provides important price signals. Time differentiation is consistent with the provisions of @ 390(b) and should be retained as an important element of SRAC pricing. The gas factor proposed by several parties is also consistent with the criteria established in AB 1890. The gas factor is necessary to yield [*20] a fair representation of the historical values required by AB 1890. Section 390 calls for a formula based on the starting price, which is then adjusted monthly by changes in the California border gas prices. The formula required by the legislation shall be implemented as shown in Attachment 1 for SCE and Attachment 2 for PG&E. This formula has been computed by using the 1995 averages for short-run avoided energy prices paid by SCE and 1994 and 1995 average for short-run energy prices paid by PG&E. The starting gas index price shall be computed as an average for the same period, as directed by @ 390. 5.3 Applicability to SDG&E Section 390 does not exempt SDG&E from this interim formula. While SDG&E currently uses its tariffed WACOG for the gas rate component to compute the monthly SRAC energy payments, it must now apply a formula approach, consistent with SCE and PG&E. On November 15, 1996, SDG&E and CCC filed a joint motion for adoption of a settlement agreement in connection with the interim SRAC formula addressed in @ 390. Under the terms of this agreement, SDG&E's starting SRAC price is based upon SDG&E's 1995 average SRAC prices and the gas indices proposed are those [*21] adopted for SCE. This settlement is reasonable, in the public interest, and shall be adopted. We also grant the joint motion for waiver of Rule 51.1(b) . The starting gas index price shall be an average of the gas index prices for 1995 using the California/Arizona (Topock) border prices reported in Natural Gas Week, Natural Gas Intelligence, and BtU Weekly. The formula required by the legislation shall be implemented by SDG&E as shown in Attachment 3. Because AB 1890 was signed into law on September 23, 1996 and was effective immediately, we direct SCE, PG&E, and SDG&E to use the adopted formula in determining their posted SRAC prices for the period beginning October, 1996. Using this interim formula will eliminate the need for litigating IERs and O&M adders in the ECAC proceedings. Because we are replacing the avoided cost index methodology with the interim formula required by @ 390, there is no longer a need for the utilities to file annual reports tracking gas costs under the avoided cost index methodology and the recorded cost methodology. 5.4 Reliability of Indices As the market continues to evolve, parties may wish to rely on new published indices. n5 Parties [*22] may file petitions to modify this decision if they wish to change the indices adopted herein. Before making this request, parties should confer regarding the accuracy and robustness of such new indices. At a minimum, we require that there be four months of reliable information available. n5 This issue was discussed in comments received in December, 1993 and January, 1994. 5.5 SRAC Based on the Power Exchange Clearing Price In the long term, @ 390 establishes that SRAC payments will be based on the clearing price paid by the independent Power Exchange:
(c) The short-run avoided cost energy payments paid to nonutility power generators by electrical corporations shall be based on the clearing price paid by the independent Power Exchange if (1) the commission has issued an order determining that the independent Power Exchange is functioning properly for the purposes of determining the short-run avoided cost energy payments to be made to nonutility power generators, and either (2) the fossil-fired generation units owned, directly or indirectly, by the public utility electrical corporation are authorized to charge market-based rates and the "going forward" costs of those [*23] units are being recovered solely through the clearing prices paid by the independent Power Exchange or from contracts with the Independent System Operator, whether those contracts are market-based or based on operating costs for particular utility-owned power plant units and at particular times when reactive power/voltage support is not yet procurable at market-based rates at locations where it is needed, and are not being recovered directly or indirectly through any other source, or (3) the public utility electrical corporation has divested 90 percent of its gas-fired generation units that were operated to meet load in 1994 and 1995. However, nonutility power generators subject to this section may, upon appropriate notice to the public utility electrical corporation, exercise a one-time option to elect to thereafter receive energy payments based upon the clearing price from the independent Power Exchange.
(d) If a nonutility power generator is being paid short-run avoided costs energy payments by an electrical corporation by a firm capacity contract, a forecast as-available capacity contract, or a forecast as-delivered capacity contract on the basis of the clearing price paid [*24] by the independent Power Exchange as described in subdivision (c) above, the value of capacity in the clearing price, if any, shall not be paid to the nonutility power generator. The value of capacity in the clearing price, if any, equals the difference between the market clearing customer demand bid at the level of generation dispatched by the independent Power Exchange and the highest supplier bid dispatched.
(e) Short-run avoided energy cost payments made pursuant to this section are in addition to contractually specified capacity payments. Nothing in this section shall be construed to affect, modify or amend the terms and conditions of existing nonutility power generators' contracts with respect to the sale of energy or capacity or otherwise.
(f) Nothing in this section shall be construed to limit the level of transition cost recovery provided to utilities under electric industry restructuring policies established by the commission.
(g) The term "going forward costs" shall include, but not be limited to, all costs associated with fuel transportation and fuel supply, administrative and general, and operation and maintenance; provided that, for purposes of this section, [*25] the following shall not be considered "going forward costs": (1) commission-approved capital costs for capital additions to fossil-fueled power plants, provided that such additions are necessary for the continued operation of the power plants utilized to meet load and such additions are not undertaken primarily to expand, repower or enhance the efficiency of plant operations; or, (2) commission-approved operating costs for particular utility-owned power plant units and at particular times when reactive power/voltage support is not yet procurable at market-based rates in locations where it is needed, provided that the recovery shall end on December 31, 2001. These requirements, for the most part, echo the parties' proposals in Joint Proposal I and II. As we move closer to the beginning of the transition period in electric restructuring (January 1, 1998), we will issue a ruling in R.94-04-031/ 1.94-04-032 to establish implementation procedures for these requirements. 6. Pending Motions CCC, CAC, n6 and IEP filed a motion on January 5, 1994 to strike portions of the December 9, 1993 comments by SCE and ORA, which they believe to be beyond the limited scope of this aspect [*26] of the proceeding, as it was originally defined. SCE filed its response on January 19, 1994. As the scope of this proceeding has been expanded, this motion is now moot. As discussed previously, two ACRs were issued which impacted the scope of this proceeding. ACR I was issued on September 20, 1995 and ACR II was issued on March 22, 1996. We therefore deny the joint motion of CCC/CAC/IEP. n6 Formerly known as the Cogenerators of Southern California. On February 16, 1996, GEA filed a petition for leave to intervene in this proceeding. GEA has approximately 40 members, consisting of all of the geothermal producers operating and selling electricity in California and several organizations which service the geothermal industry. GEA has a direct interest in the outcome of this proceeding, since several of its members are those who operate and sell power in California pursuant to QF contracts with the investor-owned electric utilities. No responses to GEA's petition were filed. Good cause being shown, we grant GEA's petition to intervene in this proceeding. On April 10, 1996, CEERT filed a motion for reconsideration of ACR II. CEERT believes that, rather than providing procedural guidance [*27] in defining the scope of this aspect of the proceeding, this ACR went beyond the findings that can be made by a single Commissioner. Events have overtaken this proceeding and AB 1890 has addressed many of the issues which CEERT was most concerned about. We therefore deny CEERT's motion as moot. Findings of Fact 1. Pursuant to PURPA, electric utilities are required to purchase electricity from QFs. 2. The Commission requires that each electric utility post monthly energy prices for QFs intended to represent the utility's own avoided costs for the coming month. 3. The energy prices consist of three elements: the IER, the UEG gas rate, and various adders, particularly the O&M adder. 4. Because the gas utilities ceased publishing a noncore portfolio price as of August 1, 1991, D.91-10-039 adopted a new means of calculating avoided energy costs, known as the index methodology. 5. Certain aspects of gas industry restructuring were not contemplated when the index methodology was adopted. 6. No party has indicated disputed factual issues for which a hearing would be necessary. 7. Application of the index methodology has been contentious and litigious. 8. PU Code @ 390 provides [*28] an interim formula for calculating short-run avoided cost energy payments to QFs. Conclusions of Law 1. It is reasonable to replace the avoided cost index methodology with an interim SRAC formula to be applicable to SCE, PG&E, and SDG&E with utility-specific components. 2. The interim SRAC formulas should reflect the utility's own avoided costs prospectively and must meet statutory requirements. 3. It is reasonable to use a simple average of California/Arizona (Topock) indices published in Natural Gas Intelligence, Natural Gas Week, and BtU Weekly for purposes of calculating monthly changes to SCE's and SDG&E's interim SRAC formula. 4. It is reasonable to use a single average of the California/Arizona (Topock) indices, as published in the publications indicated above, and a single average of the Northern California indices at Malin, Oregon, as published in Natural Gas Intelligence, Natural Gas Week, and Gas Daily for purposes of calculating monthly changes to PG&E's interim SRAC formula. 5. SDG&E is not exempt from the interim formula provided in PU Code @ 390. 6. CCC/CAC/IEP's motion to strike portions of the December 9, 1993 comments by Edison and [*29] ORA should be denied. 7. GEA's petition to intervene should be granted. 8. CEERT's motion for reconsideration of ACR II should be denied. 9. This order should be effective today, in order to allow the interim formula for short-run avoided cost energy payments to be implemented in an expedited manner. INTERIM ORDER IT IS ORDERED that: 1. The index approach for calculating the noncore gas component of avoided energy costs adopted in Decision (D.) 91-10-039 shall be replaced by the interim formula for computing short-run avoided costs (SRAC), as provided for in Public Utilities (PU) Code @ 390. This formula shall be applicable to Southern California Edison Company (SCE), Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E), as shown in Attachments 1, 2, and 3, respectively. 2. The starting values shall be applied to determine short run avoided cost postings as of October 1996. 3. The motion filed by the California Cogeneration Council, Cogenerators Association of California, and Independent Energy Producers to strike portions of the December 9, 1993 comments by SCE and the Division of Ratepayer Advocates is denied. 4. The petition [*30] for intervention filed by Geothermal Energy Associates is granted. 5. The motion filed by the Center for Energy Efficiency and Renewable Technology for reconsideration of the Assigned Commissioner Ruling issued on March 22, 1996, is denied. 6. SDG&E's and CCC's joint motion to adopt a settlement agreement for a transitional SRAC formula consistent with PU Code @ 390(b) is granted. This order is effective today. Dated December 9, 1996, at San Francisco, California. P. Gregory Conlon, President; Daniel Wm. Fessler, Jessie J. Knight, Jr., Henry M. Duque, Josiah L. Neeper, Commissioners
SRAC Transition Formula Values for Edison P[n] = [P[Base] + (P[Base] * (GP[n]-GP[Base]/GP[Base)*Factor)] * TOU
where: P[n] = Calculated based on substituting the variables below into the above formula P[Base] = 2.0808 cents/kwh (in compliance with AB 1890) GP[n] = gas price index for the period being considered GP[Base] = $ 1.3975/mmBTU Factor = .7067 TOU = Summer On-Peak 1.4251 Summer Mid-Peak (No. of Hoursin Month n - (1.4251 *No. of Summer On-Peak Hours in Month n)-(0.8526*No. of Summer Off-Peak Hours in Month n))/No. of Summer Mid-Peak Hours in Month n Summer Off-Peak 0.8526 Winter Mid-Peak 1.2185 Winter Off-Peak (No. of Hours in Month n-(1.2185*No. of Winter Mid-Peak Hours in Month n)-(0.7760*No. of Winter Super Off-Peak Hours in Month n))/No. of Winter Off-Peak Hours in Month n Winter Super-Off-Peak 0.7760 [*31]
SRAC Transition Formula and Coefficients for PG&E
PG&E's SRAC Formula uses two seta of coefficients: one set for winter months (November through April) and one set for summer months (May through October). The formula and seasonal coefficients are as follows: P[n] = [P[o] + P[o] *[(GP[n] - GP[o])/GP[o]] * Factor] * TOU
where: P[n] = SRAC price for posting period n, P[o] = Starting energy price, based on 12-month averages of recent, pre- January 1, 1996 SRAC energy prices paid by each public utility electrical corporation to non-utility power generators, GP[n] = Gas price for period [n] at the California border, GP[o] = Starting gas index price based on an average of California border index gas prices for the same annual periods as the starting energy price; Factor = Gas factor, and TOU = Time-of-Use factor, calculated as follows: Summer Peak 1.065 Partial-Peak 1.022 Off-Peak [No. of hours in Month n - (1.065 * No. of Summer Peak hours in Month n)- (1.022 * No. of Summer Partial-Peak hours in Month n) - (.0946* No. of Summer Super Off-Peak hours in Month n)]/No. of Summer Off-Peak hours in Month n Super Off-Peak 0.946 Winter Partial-Peak 1.032 Off-Peak [No. of hours in Month n - (1.032 * No. of Winter Partial-Peak hours in Month n) - (0.950 * No. of Winter Super Off-Peak hours in Month n)]/No. of Winter Off-Peak hours in Month n Super Off-Peak 0.950 [*32] PG&E SRAC Formula Seasonal Coefficients Season P[o] GP[o] Factor (c/k Wh) (S/MMBtu) Winter 2.3973 1.6394 0.7875 Summer 1.8748 1.4457 0.6270
SRAC Transition Formula Values for SDG&E P[n] = [P[Base] + P[Base] * [(GP[n] - GP[Base])/GP[Base] * Factor] * TOU where: P[n] = calculated based on substituting the variables below P[B]ase = 2.2181 cts per kWh (in compliance with AB1890) GP[n] = an average of the gas index prices for the period being considered using the California/ Arizona (Topock) border prices reported in Natural Gas Week Natural Gas Intelligence and BTU Weekly GP[Base] = $ 1.3975 per mmBtu Factor = 0.605 TOU (Time of Use) = 1.059 Summer On-Peak Conversion Factor) 1.028 Summer Semi-Peak 0.889 Summer Off-Peak 0.750 Summer Super Off-Peak 0.931 Summer Non-TOU 1.165 Winter On-Peak 1.136 Winter Semi-Peak 1.038 Winter Off-Peak 0.864 Winter Super Off-Peak 1.049 Winter Non-TOU
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