Southern California Edison Co. v. Public Utilities Commission

124 Cal. Rptr. 2d 281, 101 Cal. App. 4th 384

• Court: California Court of Appeal
• Decided: September 10, 2002
• Docket: B151560, B152003
• Status: Published

Opinion

Opinion

MUNOZ, J. *

We issued a writ of review to consider the lawfulness of certain rulings by the Public Utilities Commission (Commission), adjusting the prices public utilities must pay to small privately owned electric generation facilities. (Pub. Utilities Code, § 1756.) We affirm that part of the ruling adopting a new methodology for determining the amount due, but we annul that part of the ruling that conflicts with federal regulations.

Procedural Background

In Cal.P.U.C. Decision No. 01-01-007 (Jan. 4, 2001) [2001 Cal.P.U.C. Lexis 66] (hereafter Decision) the Commission adjusted a component of the prices electric utilities are required to pay for purchases of electricity from certain electric generation facilities. In Cal.P.U.C. Decision No. 01-06-043 (2001) (hereafter Denial of Rehearing) the Commission denied the applications for rehearing. Caithness Energy (Caithness) filed its petition for writ of review in the Fourth Appellate District. The Supreme Court ordered the matter transferred to this court on the Fourth District’s request to be heard along with the petition filed by Southern California Edison Company (Edison). (Pub. Util. Code, § 1756.) We affirm the decision of the Commission changing the methodology of determining line losses and annul that part that sets a 0.95 floor on transmission loss factors.

Facts

1. Federal History and Regulations

In 1978, in response to the energy crises of the 1970’s, Congress enacted the Public Utility Regulatory Policies Act of 1978 (PURPA). (Pub.L. No. 95-617, § 2 (Nov. 9, 1978) 92 Stat. 3117.) In order to promote the development of more efficient means of generating electricity, Congress provided certain benefits and exemptions for qualifying cogeneration facilities 1 and small power production facilities. 2 Those energy producers are collectively referred to as qualifying facilities (QF’s).

Section 210 of PURPA 3 ordered the Federal Energy Regulatory Commission (FERC) to come up with rules to implement the congressional intent and specifically “to encourage cogeneration and small power production.” The FERC subsequently adopted those rules, which were codified as 18 Code of Federal Regulations part 292 et seq. (2002). The regulations require electrical utilities to purchase energy or capacity made available by a QF (18 C.F.R. § 292.303(a) (2002)) at prices equivalent to the utilities’ “avoided costs.” (18 C.F.R. § 292.304(b) (2002).) “Avoided costs” are defined as “the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source.” (18 C.F.R. § 292.101(b)(6) (2002).) In other words, “avoided cost is not measured by what utilities are paid when they sell energy, but instead by what they must spend to produce or procure [that] energy in the absence of QFs.” (Re San Diego Gas & Electric Co. (Mar. 4, 1999) No. 99-03-021 [1999 Cal.P.U.C. Lexis 384] (hereafter Decision. No. 99-03-021).) The regulations further provide that the costs paid are to be fair and reasonable to the electric consumer of the electric utility and in the public interest and not be discriminatory against the QF’s. (18 C.F.R. § 292.304(a) (2002).) The same regulation also provides that public utilities need not pay QF’s more than the avoided costs. (Ibid.) Finally, the FERC regulations require the state regulatory authority, in determining the “avoided costs” to take into account, to the extent practicable, the costs or savings related to “line losses” incurred by or accrued to the utility as a consequence of purchasing power from QF’s rather than generating the power itself. (18 C.F.R. § 292.304(e)(4) (2002).)

Line losses are those unavoidable losses that occur when electricity is transmitted from the point of generation to the point of consumption. They result from the dissipation of energy, in the form of heat, caused by resistance as the electricity travels over transmission or distribution lines. There are a number of variables which cause these losses, such as the temperature and the resistance of the line, but the main factor appears to be the distance between the generating source and the point of consumption. 4 “Line loss factors” (LLF’s) or “energy loss adjustment factors” (ELAF’s) are generally expressed as something greater than 0 and less than 1.0. In rare circumstances the figure will be greater than one. Basically, the figure is a measure of the amount of power lost between the generating source and the point of consumption. Thus, for example, a figure of 0.95 indicates that 5 percent of the power was lost enroute to the public utility.

2. The Commission’s Application of the FERC Regulations Prior to Deregulation

In September of 1980, the Commission, which is charged with implementing PURPA in California (16 U.S.C.A. § 824a-3(f)(1)), instituted a proceeding to implement the FERC regulations. (See Commission Rules Regarding Electric Utility Purchases of Electric Power from Cogeneration and Small Power Production Facilities (1982) 8 Cal. P.U.C.2d 20, 27 (Cogeneration and Small Power Production Facilities) (Cal.P.U.C. Dec. No. 82-01-103).) The Commission promulgated a series of regulations, which set line loss factors to be applied in order to determine the avoided cost-based energy prices paid to QF’s. As part of the initial implementation of PUKPA, the Commission ordered Edison and other utilities to include costs or savings from their line losses in their avoided cost energy payments to QF’s and to perform studies of their line losses. (Cogeneration and Small Production Facilities (Dec. No. 82-01-103), supra, pp. 119-120.) At that time the Commission set the Edison loss factors at 1.023 for transmission lines and 1.026 for lines connected at the primary distribution level. In response to a request for back credits by the QF’s the Commission stated, “Such a step would suggest that the evidence on this issue is definitive. Instead, our decision reflects the inconclusiveness of the record on line losses and our struggle to develop an appropriate interim solution until the line loss studies are completed, reviewed, and approved.” (Re Pacific Gas & Electric Co. (1984) 14 Cal.P.U.C.2d 489, 509.)

In 1987 the Commission, based upon Edison’s 1985 study of its average systemwide marginal line losses, revised the line loss factors to 1.026 for QF’s interconnected at the distribution level and 1.023 for QF’s interconnected at the transmission line level. (Re Southern Cal. Edison Co. (1987) 26 Cal.P.U.C.2d 392.)

The line loss studies, requested in 1984, were never completed and, in 1988, while declining to revisit the line loss methodology, the Commission pessimistically stated, “We see little benefit at this time to refining the treatment of line losses in our established methodology for pricing energy from existing QFs, or even future QFs under the short run standard offers. Not only are the studies old and likely to need revision, but also the issues involved in making line loss adjustments for such QFs are complex, and there is no assurance that after wrestling with these issues, we would emerge with significantly improved price signals to QFs.” (Re Pacific Gas & Electric Co. (1988) 29 Cal.P.U.C.2d 263, 284.)

3. The Effect of Deregulation

In 1996 the California Legislature enacted Assembly Bill No. 1890, 5 which restructured and deregulated the electrical industry. As part of restructuring, an Independent System Operator (ISO) was created. (Pub. Util. Code, §§ 330, subd. (m), 345-352.5.) The ISO was under and subject to the jurisdiction of the FERC (Pub. Util. Code, § 346) and assumed responsibility for scheduling the transmission of power throughout its statewide “control area.” (Pub. Util. Code, § 330, subd. (m).) This was a change from the traditional practice of each regional utility servicing its provincial service territory. On October 30, 1997, the FERC authorized limited operation of the California ISO pursuant to a tariff approved by the FERC. The tariff approved by the FERC provided for the application of a generation meter multiplier (GMM) to energy transmitted over energy lines in the ISO control area. (Re PG&E, SDG&E and SCE (Oct. 30, 1997) 81 FERC If 61,122.) GMM’s were used by ISO and the California Power Exchange (PX) 6 to adjust payments to sellers of power in order to account for decreases in the amount of energy actually delivered by a seller as a result of line losses. The ISO assigned a GMM to every seller in the market, including QF’s.

On November 19, 1999, the Commission issued an Order Instituting Rulemaking Into Implementation of Public Utilities Code Section 390 (Rule-making 99-11-022 filed Nov. 18, 1999 [2002 WL 1277101].) Less than a month later, on December 7, 1999, Edison filed a prehearing conference statement indicating that the scope should include an inquiry into the need to update the existing ELAF’s. A commissioner was assigned to the matter and, in January 2000, he issued a scoping memo and ruling indicating that the scope of the section 390 7 rulemaking should include an inquiry into the need to update the existing ELAF’s. He further ordered the Commission’s Energy Division to conduct a workshop on the issues, which was to be followed by evidentiary hearings in the event there was no consensus following the workshop. Later that month, on January 31, 2000, the Office of Ratepayer Advocates (ORA) 8 and Edison filed workshop comments urging the 1987 loss factors be replaced by QF specific GMM’s which were developed and implemented by the ISO and which were being used by the ISO and the PX to account for line losses associated with electricity purchased and sold in the ISO market area. GMM’s were developed and are used by the ISO to determine the impact on system losses caused by the generation from a particular generator. GMM’s are calculated for each generator and bus and intertie 9 every hour. The GMM’s are first forecast and published seven days in advance. There is also an hour ahead GMM, also known as the ex post GMM, that is also published.

Thereafter, on February 15 and 16, 2000, a workshop on the methodology for adjusting short run avoided cost energy payments to QF’s was held. After comments by interested parties, a report was issued by the Energy Division of the Commission. Even though there was no consensus, the report recommended the Commission develop a new ELAF based upon the ISO’s GMM methodology.

Because of a lack of consensus, the Commission ordered evidentiary hearings on the issue of whether line loss factors for Edison and the two other principal investor-owned utilities 10 should be updated. Interested parties submitted prepared direct testimony on April 28, 2000. Prepared rebuttal testimony was submitted on May 8, 2000. Evidentiary hearings were held on May 11 and 12, 2000. Opening briefs were filed on June 1, 2000, and reply briefs were filed on June 14, 2000.

Commissioner Neeper, the commissioner assigned to the project, issued a proposed decision on September 5, 2000. In discussing line loss factors the proposed decision stated, “We will adopt GMMs as the TLFs [Transmission Loss Factors] once the Commission has made the required findings under Section 390(c) [regarding whether the market is ‘functioning properly’ for the purpose of determining avoided cost] and QFs are paid a PX-based energy price. Until that time, effective with the first posting following this decision, we adopt a TLF equal to GMMqf/GMMsys.” 11 Comments on the proposed decision were filed by interested parties on October 2, 2000. Replies were filed on October 13, 2000.

By November 2000, matters in the California power market had degenerated to such an extent that, on November 1, 2000, the FERC issued an order proposing elimination of the requirement that the three investor-owned utilities must sell into and buy from the PX. (San Diego Gas & Elec. Co. v. Sellers of Energy (Nov. 1, 2000) 93 FERC ¶ 61,121.) As a result, Commissioner Neeper issued a ruling requesting interested parties to comment. Comments xyere filed on December 11, 2000. There was a general consensus that the PX market was not working correctly, but there was a lack of consensus as to a possible solution.

On December 15, 2000, the FERC’s order became final. About three weeks later, on January 4, 2001, the Commission filed a truncated version of Commissioner Neeper’s September 5th proposed decision. The revised decision addressed only the issue of line losses and ruled that the GMMqf/ GMMsys formula was to be used for the transmission loss factor. However, because of the possible impact of payments to remote QF’s, the Commission found “that the societal benefits associated with resource diversity and the environmentally-preferred energy production offered by renewable resources merits special treatment for renewable QFs. Therefore, we will adopt a floor for the TLF of 0.95 for QFs relying on renewable resources for their fuel sources.” (Decison, supra, 2001 Cal.P.U.C. Lexis 66.)

The petitions for rehearing by Edison and Caithness were denied on June 14, 2001. These writs followed. (§ 1756.)

The Caithness Petition

Initially, the Commission argues that Caithness cannot assert the grounds urged since they were not asserted before the Commission and have therefore been waived. (§ 1732.) Caithness responds by arguing that these points were raised before the Commission. A comparison of the contentions made before this court and those made to the Commission reveals sufficient similarity so as to find no waiver.

Caithness initially contends the Commission’s Decision, 2001 Cal.P.U.C. Lexis 66, is in error because it does not meet PURPA’s requirements for an accurate measurement of: (1) the losses experienced when electricity is purchased from QF’s and brought to the load center; 12 and (2) what those losses would be if the utility purchased the electricity from another source. Under the FERC regulations approach, the Commission is required to compare the two and determine if there are costs or savings and adjust the full avoided cost accordingly. Since the methodology used is basically an accounting procedure, Caithness urges, it cannot be used to measure line losses. Therefore, Caithness argues, the ruling should be annulled by this court and the old fixed ratios reinstated.

However, the argument presupposes and assumes that the old fixed ratios were accurate, an assumption not supported by the record. In addition to the questions already noted, a 1992 study by the Division of Ratepayer Advocates, the predecessor to ORA, had concluded the existing line loss factors were essentially “flawed.” In 2000 ORA, in comments to the Commission stated: “No party advocating retention of existing line loss factors put forth any affirmative evidence that existing line loss factors reflect current line loss costs or savings. The primary evidence put forth was based on what might have happened many years ago.” As pointed out by Edison, the marginal loss approach used by the Commission, prior to adoption of the GMM methodology, assumed the QF’s managed to avoid all utility losses. Because the figures then in place were greater than 1.0, the net effect of the fixed ratios was that the QF electric power always reduced losses. Such a possibility, under certain circumstances, had been foreseen by the FERC in its regulations: “If energy produced from a qualifying facility undergoes line losses such that the delivered power is not equivalent to the power that would have been delivered from the source of power it replaces, then the qualifying facility should not be reimbursed for the difference in losses. If the load served by the qualifying facility is closer to the qualifying facility than it is to the utility, it is possible that there may be net savings resulting from reduced line losses. In such cases, the rates should be adjusted upwards.” (Small Power Production and Cogeneration Facilities; Regulations Implementing Section 210 of the Public Utility Regulatory Policies Act of 1978, 45 Fed.Reg. 12214, 12227 (Feb. 25, 1980.)

Notwithstanding the unique circumstances envisioned by the authors of the regulations above, the Commission was aware that there were problems with the old method of determining the rates as to the majority of the QF’s. In addition to the 1988 doubts about the pricing structure for QF’s (Re Pacific Gas & Electric Co., supra, 29 Cal.P.U.C.2d 284), the Commission had in 1982 indicated that the factors then in place were reasonable, but only for the interim. (Re Pacific Gas & Electric Co., supra, 14 Cal.P.U.C.2d 489, 509.) In Decision No. 99-03-021, supra, 1999 Cal.P.U.C. Lexis 384, the Commission denied the request of San Diego Gas and Electric Company (SDG&E) to modify the transmission line adjustments factors. However, it did allow modification of the distribution line adjustment factor. SDG&E had sought to use GMM’s as the measure of payment for short-run avoided cost calculations. In rejecting the request, the Commission noted that the GMM’s measure the power flow throughout the system and did not measure losses or gains within the SDG&E system. (Dec. No. 99-03-021, supra.)

In a concurring opinion, Commissioner Neeper wrote, “It is clear to me that the present methodology is incorrect. At this time, TLFs are set at 1.025 for all QFs, which represents a 1982 study that assumed that QFs impose zero transmission line losses on the system. That is irrational. QFs which use the transmission system must impose some line losses (even if minuscule), meaning that the TLF in use today is biased toward overpayments to QFs. Further, because various QFs impose different levels of line losses (and these line losses vary over time), the use of a single TLF must be inaccurate. Clearly, it is reasonable to seek a more refined methodology.

“The GMM method purports to measure the specific line losses imposed by each QF through an ‘incremental’ calculation performed by the ISO (and potentially to do so on an hourly basis). Thus, using GMMs could resolve each of the imperfections of today’s method. It has the advantages of being QF-specific, potentially time-differentiated, and calculated by an impartial body. Even if imperfect, there is a strong likelihood that this would represent an improvement over what exists today.

“However, GMMs are not perfect, as established in great detail in the record. And the problem is twofold. First, we do not have any objective standard of perfection to measure against, so we do not know how imperfect GMMs would be. This leads to the second problem: it is quite possible that GMMs would be biased against some, most or all QFs, leading to underpayments. Even if, as is likely, any overall level of underpayments with GMMs would be less than the overall level of overpayments today, I do not believe it is appropriate to change from one demonstrably systematically-biased methodology to a potentially systematically-biased methodology going in the other direction. This is the hurdle parties favoring GMMs will have to leap in order to convince me of its appropriateness in the Section 390 proceeding.” (Dec. No. 99-03-021, supra, 1999 Cal.P.U.C. Lexis 384.)

Subsequently, the hearings were held, testimony was taken, cross-examination was allowed and recommendations were made. Caithness now urges that the Commission committed legal error because “the GMM method is inherently incapable of performing the comparison the FERC regulations require.”

The Commission specifically found that the existing methodology for addressing line losses was not acceptable because:

1. The recent SDG&E TLF study suggests that the existing TLF’s in place for SDG&E are much too high, leading to significant ratepayer losses;

2. Decision 99-03-021, supra, 1999 Cal.P.U.C. Lexis 384 explains that SDG&E’s and SCE’s current TLF’s were based on a study that “assumed that all of the marginal line losses would be avoided by the operation of QFs” a difficult assumption to justify; and

3. Existing TLF’s treat QF line losses in the aggregate, leading to a less fair and efficient outcome. (Dec. No. 99-03-021, supra, 1999 Cal.P.U.C. Lexis 384.)

Accordingly, the Commission concluded, “replacing the existing TLFs with a simple factor of 1.000, unless there is a better methodology available, would be preferred to the existing factors. With the advantages noted above, GMMs appear to provide a superior methodology.” (Decesion, supra, 2001 Cal.P.U.C. Lexis 66.)

The advantages of GMM’s are: “1. GMMs have been developed and are calculated by the ISO, a neutral, knowledgeable party; 2. GMMs are specific to individual QFs, and consequently more accurate than any single number applied to all QFs; 3. GMMs vary by hour, and thus more accurately reflect the impact on line losses; 4. GMMs have been developed expressly to calculate the impact on system line losses due to power inputs from a given generator; 5. GMMs are being used by the market for purposes of calculating line losses; and 6. GMMs are readily available, and practical.” (Decision, supra, 2001 Cal.P.U.C. Lexis 66.) The Commission also found PURPA only required the Commission to find losses in comparison to the cost of power elsewhere. There is no PURPA requirement that the line loss factors be within the system. (Ibid.)

The Commission was aware of its duties under PURPA and in arriving at the formula of GMMqf/GMMsys. In response to the contention that use of the GMM’s violated PURPA, the Commission noted “PURPA requires that line losses be compared to those that would have existed had the purchasing utility not purchased from QFs.

“While QFs are paid based on Section 390(b), GMMs alone do not accomplish this comparison. We find that the formula—GMM[QF]/GMM[SYS]—accomplishes the comparison [13] required by PURPA.” (Decision, supra, 2001 Cal.P.U.C. Lexis 66.)

Caithness does not ask this court to set aside the factual determinations concerning the use of the GMM data to determine line losses, nor does it attack the formula actually implemented. Instead it asks this court to substitute its judgment for that of the Commission, the entity legally charged with making this determination. However, this we cannot do. (§ 1757.1.) 14 We are limited to determining, in light of the total record, whether: (1) the order or decision of the commission was an abuse of discretion; (2) the commission has not proceeded in the manner required by law; (3) the commission acted without, or in excess of, its powers or jurisdiction; (4) the decision of the commission is not supported by the findings; (5) the order or decision was procured by fraud; or (6) the order or decision of the commission violates any right of the petitioner under the Constitution of the United States or the California Constitution. (§ 1757.1.) (See also City of Vernon v. Public Utilities Com. (2001) 88 Cal.App.4th 672, 677-678 [106 Cal.Rptr.2d 145].)

We have reviewed the evidence upon which the Commission based its decision. The Commission was faced with TLF’s that it knew were incorrect and had the effect of overcompensating the QF’s in violation of PURPA. (See 18 C.F.R. § 292.304(a)(2) (2002); Southern Cal. Edison Co. (Feb. 23, 1995) 70 FERC ¶ 61,215 at p. 61, 675.) The Commission did what PURPA required: It held hearings, heard conflicting evidence and determined that the GMM approach was the best method for measuring line losses. The Commission then took a second step and devised a formula, using GMM methodology, to be used for determining the impact on system line losses that occurs when a QF’s power is brought into the overall power system as compared to what would have occurred had the utility procured its power elsewhere. That is all that PURPA requires.

In this case there was no abuse of discretion, the Commission proceeded in a manner authorized by law and there were no violations of Caithness’s constitutional rights. Additionally, Caithness has not presented this court with any valid reason why the decision should be annulled. Therefore, since the decision is supported by substantial evidence, the decision is affirmed.

The Edison Petition

As part of the Decision, the Commission ruled: “We recognize, however, that adoption of the GMM based line loss methodology may impact payments to QFs who are located in remote areas, especially renewable generators. We find that the societal benefits associated with resource diversity and the environmentally-preferred energy production offered by renewable resources merits special treatment for renewable QFs. Therefore, we will adopt a floor for the TLF of 0.95 for QFs relying on renewable resources for their fuel sources.” In its Denial of Rehearing the Commission, in response to Edison’s contentions took the position that the 0.95 floor was permitted by PURPA and the FERC regulations.

Edison contends that this part of the Decision should be annulled because the 0.95 floor violates federal law. Edison further states that it deals with more than 300 QF’s which are located in locales that are far removed from Edison’s main load which is the Los Angeles basin. The QF’s range from wind technology projects in the Tehachapi Mountains and Palm Springs area to geothermal technology projects located in the Saltón Sea and Owens Valley areas. During the past two years Edison states that it has paid between $2.3 billion and $3.5 billion for QF electric deliveries.

Because Edison is required to pay pursuant to the 0.95 floor regardless of actual losses, Edison contends the Commission has set in place a payment methodology in violation of federal regulations. (See Connecticut Light and Power Co. (Jan. 10, 1995) 70 FERC ¶ 61,012, 61,029); Southern Cal. Edison Co., supra, 70 FERC ¶ 61,215, 61,675.) Caithness 15 and the Commission both argue this is a permissible action under PURPA. We have concluded that the Commission’s decision in setting a 0.95 for QF losses was an abuse of discretion and impermissible under PURPA.

PURPA was enacted in order to try and lessen this country’s dependence on foreign oil. The purpose of parts I and III of PURPA was to: (1) encourage the conservation of electricity; (2) encourage the efficient use of electricity; and (3) encourage equitable rates to consumers. (See FERC v. Mississippi (1982) 456 U.S. 742, 746 [102 S.Ct. 2126, 2130-2131, 72 L.Ed.2d 532].) However, in actuality, the states were not required to do anything. Instead they were merely ordered to consider certain procedures, but there was no requirement that they act in any certain manner once they had considered those procedures. (Id. at pp. 749-750 [102 S.Ct. at pp. 2132-2133].)

Part II of PURPA dealt with QF’s. Congress was especially concerned with the reluctance of traditional electrical utilities to purchase from and sell power to QF’s and the financial burden being placed upon QF’s by state and federal regulators. (FERC v. Mississippi, supra, 456 U.S. at pp. 750-751 [102 S.Ct. at pp. 2132-2133].) Accordingly, FERC was ordered to make such rules as necessary to encourage cogeneration and small power production. (16 U.S.C.A. § 824a-3(a).) In regards to the status and determination of QF status, FERC was given exclusive authority. (Independent Energy Producers Ass ’n, Inc. v. CPUC (9th Cir. 1994) 36 F.3d 848, 856.)

The California Legislature has likewise ordered the Commission to review charges paid by QF’s and to make adjustments to those charges to encourage the generation of power by QF’s. (§ 2824.) In ordering the elimination of the requirement to sell into and buy from the PX the FERC stated, “Calpine and Cogeneration Association have raised legitimate concerns regarding the pricing and associated availability of Cogeneration QF resources in the California market. However, as stated by Cogeneration Association, this issue derives from the California Public Utility Code and in the first instance is within state authority. In this order, we eliminate the PX buy/sell requirement and terminate the PX rate schedule. These changes to the California market structure require necessary actions by California authorities in order to determine the appropriate avoided cost rate for Cogeneration QF power, a determination, as stated by PUKPA, within the purview of the states.” (San Diego Gas & Electric Co. v. Sellers of Energy, supra, 93 FERC ¶ 61,294, 62,018.)

However, in Independent Energy Producers Ass ’n, Inc. v. CPUC, supra, 36 F.3d 848, 856 the court after discussing the broad powers that the states were given to determine avoided costs and approve and disapprove contracts, issued a caveat, “In implementing its regulations, the Commission clearly weighed Congress’s desire to promote cogeneration while not burdening ratepayers, and concluded that requiring utilities to pay full avoided costs properly balanced these interests. (18 C.F.R. § 292.304(d); Administrative Determination, IV Federal Energy Reg. Comm’n Rep. (CCH) ¶ 32,457, at 32,158 (recognizing that ratepayers should be indifferent to the source of power and that if rates are set at the utility’s avoided costs, ratepayers will pay neither more nor less than they otherwise would have). If purchase rates are set at the utility’s avoided cost, consumers are not forced to subsidize QFs because they are paying the same amount they would have paid if the utility had generated energy itself or purchased energy elsewhere.” (Independent Energy Producers Ass’n. Inc. v. CPUC, supra, at p. 858, italics omitted.)

Here, by setting a 0.95 floor on transmission loss factors, the Commission crossed the line. Congress has clearly indicated an intent to preempt the field in the area of energy regulation and had expressed that intent in section 824(a) of 16 of the United States Code Annotated. Title 16 United States Code Annotated section 824a-3(f) allows: the “States” great latitude in implementing rate making subject to the FERC rules. The FERC rule for rate making provides: “(1) Rates for purchases shall: [¶] (i) Be just and reasonable to the electric consumer of the electric utility and in the public interest; and [¶] (ii) Not discriminate against qualifying cogenerator and small power production facilities. [¶] (2) Nothing in this subpart requires any electric utility to pay more than the avoided costs for purchases.” (18 C.F.R. § 292.304(a) (2002), italics added.)

The Commission argues that section 2824 gives it the authority to make adjustments to help QF’s and that this is in the public interest. There is no question that the Commission’s actions are normally presumed valid. (See Greyhound Lines, Inc. v. Public Utilities Com. (1968) 68 Cal.2d 406, 410-411 [67 Cal.Rptr. 97, 438 P.2d 801].) However, the FERC has specifically stated that electrical utilities are not to be required to pay more than the avoided cost for purchases of electricity from QF’s. The Commission is mandated to follow and implement any rules that the FERC prescribes. (16 U.S.C.A. § 824a-3(f).) The 0.95 ruling by the Commission essentially usurps the FERC’s authority in determining that the ratepayers shall not support the alternative energy industry. (See 16 U.S.C.A. § 824a-3(b).) This it cannot do. (See Independent Energy Producers Ass’n, Inc. v. CPUC, supra, 36 F.3d at p. 856.)

The Commission’s argument that the 0.95 rate issue is moot fails. The Commission’s own argument indicates there are some QF’s that have not yet signed the fixed energy rate agreements that are apparently now being used with the Commission’s approval.

Finally, Caithness’s argument that, if the 0.95 floor fails, the Decision should be overruled, is rejected. A reading of the Decision makes it clear that the Commission was convinced the old fixed rates for determining line losses were incorrect. If the GMM methodology had not been adopted, then the factor of 1.00 for line losses would have been used. (Dec. No. 99-03-021, supra Cal.P.U.C. Lexis 384.) The 0.95 floor was almost an afterthought to the conversion to the GMM methodology. There is no reason to set aside the Decision.

Conclusion

The conversion to the GMM methodology for determining TLF’s was a valid exercise of the Commission’s decision making authority under PURPA. It may be that there is a valid reason for the 0.95 rule. However, the Commission did not cite any evidence in the Decision, nor has it presented this court with any reason other than the impermissible one: “The societal benefits associated with resource diversity and environmentally preferred energy production by renewable resources merits special treatment for renewable QFs.”

Disposition

The decision is affirmed in part and annulled in part. That part of Decision No. 01-01-007 that imposes a GMM based formula for TLF’s is affirmed. That portion of the Decision that places a 0.95 floor on the TLF is annulled.

Lillie, P. J., and Perluss, J., concurred.

A petition for a rehearing was denied September 17, 2002, and on September 10, 2002, the opinion was modified to read as printed above. The petition of petitioner Caithness Energy for review by the Supreme Court was denied November 13, 2002. Baxter, J., and Chin, J., did not participate therein.

* Judge of the Los Angeles Superior Court, assigned by the Chief Justice pursuant to article VI, section 6 of the California Constitution.

1 A “cogeneration facility” is a facility that produces electric energy and steam or forms of useful energy (such as heat) which are used for industrial, commercial, heating or cooling purposes. (See 16 U.S.C.A. § 796(18)(A).)

2 A “small power production facility” is an eligible solar, wind, waste or geothermal facility, which produces electricity. (See 16 U.S.C.A. § 796(17)(A).)

3 16 United States Code Annotated section 824a-3.

4 The practical effect is that what the QF generates may or may not be what the public utility receives. For example, if the QF generates 100 watts of power and there is a 2 percent line loss, the public utility will only receive 98 watts. Under the FERC regulations, the public utility only has to pay for what it received, not what was generated and sent.

5 Statutes 1996 chapter 854 (Assem. Bill No. 1890) section 10, effective September 24, 1996.

6 The PX was intended to provide an efficient competitive auction for all suppliers. (Pub. Util. Code, § 355.)

7 Further references to a section with a number shall be references to a Public Utilities Code.

8 ORA is a consumer advocacy division of the Commission.

9 An intertie is a border point between adjacent transmissions and territories.

10 The other two are Pacific Gas and Electric Company and San Diego Gas and Electric Company.

11 ”Sys”is the system average.

12 The place where the electricity is ultimately consumed.

[13] 13See Code of Federal Regulations, title 18, section 292.304(e) (2002).

14 The parties are in disagreement as to whether section 1757 or 1757.1 applies to this proceeding. The commissioner assigned to the case declared the proceeding as “quasi-legislative.” Since this is not a complaint or enforcement proceeding nor a ratemaking or licensing procedure that is addressed to specific parties, this court is of the opinion section 1757.1 applies.

15 Caithness, while not conceding its position that the GMM methodology is improper, nonetheless realizes that this court may disagree. In the event this court found the GMM methodology proper, which it has, then Caithness argues the 0.95 limitation is proper.