Decision 96-12-088 December 20, 1996

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

INTERIM OPINION

I. Introduction

Today, we provide the parties and the public with an updated roadmap to the crucial and necessary steps to accomplish electric utility industry restructuring. Generally, the enactment of Assembly Bill (AB) 1890 (Stats. 1996, Ch. 854), signed into law on September 23, 1996, necessitates some adjustment to our original Roadmap Decision, which set forth a "procedural plan for achieving the transition to a restructured electric services industry serving California customers." (Decision (D.) 96-03-022, p. 2 (mimeo).) Although AB 1890 reaffirmed many aspects of our Preferred Policy Decision,(1) this legislation resolved some of these issues differently. As a result of the legislation, some new proceedings will be required and others will be changed in scope.

The timeline provided in our original Roadmap Decision has necessarily changed as we have embarked on the many interrelated proceedings critical to ensuring that the market structure and supporting elements of the transition period leading to a competitive generation framework are in place no later than January 1, 1998. The assigned Commissioners have held scoping workshops in their major issue areas and have issued numerous rulings, some of which have revised filing dates and the scope of activities. Today, we set forth these changes in one order, our updated Roadmap Decision.

Furthermore, since the enactment of AB 1890, we have been assessing the impacts of this legislation on several areas in our Preferred Policy Decision, especially in terms of how this Commission will go forward. As part of this assessment, we have requested the parties to comment on the effects of AB 1890 in several areas, including direct access, voluntary divestiture, market power, return on equity, the mandatory buy-sell requirement, the interim competition transition charge (ICTC), and the applicability of the California Environmental Quality Act (CEQA). (See e.g. Joint Assigned Commissioners' Ruling of September 27, 1996 (JACR on Direct Access); Coordinating Commissioner's Ruling of September 30, 1996 (CCR); Administrative Law Judge's Ruling of September 20, 1996 (ALJ Ruling on ICTC); and Assigned Commissioner's Ruling of October 11, 1996 (ACR on Divestiture).)

Beside providing an updated roadmap, this order also discusses what impact, if any, AB 1890 has had on certain areas in the Preferred Policy Decision. In particular, we look at specific issues in the following areas: voluntary divestiture, return on equity, the mandatory buy-sell requirement, and direct access, and have reached some conclusions. With respect to other issues not discussed in this order, we intend to address them as we continue to proceed expeditiously in implementing our Preferred Policy Decision and AB 1890.

Therefore, we discuss the activities underway and present the current or planned schedules in the major issue areas. These schedules represent our best estimate of the dates, major issues, and necessary activities in the various proceedings. While these schedules may necessarily change to some extent, they represent our timeline to effectuate the beginning of the transition period for electric restructuring no later than January 1, 1998. We emphasize that the Coordinating Commissioner will continue to facilitate and coordinate these complex, interrelated proceedings.

In addition, as discussed below, a policy-level Environmental Impact Report (EIR) is no longer required under CEQA. However, specific Commission action during the transition to competition may have CEQA implications which must be considered. Therefore, applications and working group reports which require our approval must explicitly comply with the applicable requirements of Rule 17.1 of our Rules of Practice and Procedure.

As a general rule, as we embark upon and continue with the many proceedings necessary to arrive at the beginning of this new world, we must also be cognizant of potential affiliate transaction problems. We will review our affiliate transaction rules and determine whether they must be modified to consider potential self-dealing and cross-subsidization issues that may arise as a result of electric utility restructuring.

II. Market Structure Issues

Our Preferred Policy Decision directed the establishment of a Power Exchange (PX) and an Independent System Operator (ISO). Legislative support for these institutions was codified in AB 1890. On April 29, 1996, Pacific Gas and Electric Company (PG&E), Southern California Edison Company (Edison), and San Diego Gas & Electric Company (SDG&E) ("Applicants") submitted three joint filings to the Federal Energy Regulatory Commission (FERC).

II.A. FERC Issues

Below we briefly summarize the joint filings relating to the ISO and the PX, their status, and expected next steps.

II.A.1. Petition for Declaratory Order (FERC Docket No. EL96-48-000)

This Petition for Declaratory Order requested that the FERC: 1) ensure that this Commission will have adequate jurisdiction to permit the recovery of transition costs from all retail customers; 2) identify which facilities should be placed under control of the ISO; and 3) clarify the scope of the FERC's and this Commission's ratemaking authority. Several days after this filing was submitted, the FERC issued Order No. 888, providing guidance regarding the delineation of transmission and local distribution facilities.

On June 13, 1996, we intervened, citing Order No. 888 and the FERC's intention to defer to state determinations on the transmission/distribution issue. In light of this development, we held a technical workshop on July 10 to review the Applicants' proposed transmission/local distribution delineation and evaluate the comments filed in response to their proposal. On August 15, we filed Supplemental Comments with the FERC, including the transcript of the July 10 technical workshop and all comments filed in the state proceeding, generally endorsing the delineation of facilities in the Applicants' Petition, with the exception of reclassifying Edison's radial generation ties and San Onofre Nuclear Generating Station (SONGS) facilities as generation.

On October 30, the FERC issued a decision setting forth the transmission and distribution split, deferring to this Commission's endorsement of the delineation of transmission and local distribution facilities, for the purposes of the state's retail access initiative. This split will be used to develop a cost of service for the transmission tariffs to be filed at the FERC. The FERC granted the Applicants' request for a declaration that facilities may have multiple uses and that the initial classifications of facilities as transmission or local distribution are subject to change as the uses of the facilities change. The FERC also found that the request for a declaratory order was not the appropriate vehicle for addressing the issue of which transmission facilities should be subject to the operational control of the ISO. The seven indicators of local distribution, set forth in Order No. 888, were developed by the FERC for jurisdictional purposes, not for determining what facilities should be or should not be under the control of an ISO. The FERC stated that it will make an independent determination of which facilities should be under the operational control of the ISO, based on the principles in Order No. 888 and other relevant criteria, in the ISO docket. The FERC agreed with this Commission that the jurisdictional split between transmission and local distribution will not predetermine transmission pricing, cost allocation or rate design determinations at either the state commission or at the FERC. Again, the FERC will address those issues in the context of the ISO application, discussed below.

II.A.2. Application to Convey Operational Control of Designated Jurisdictional Facilities To An Independent System Operator (FERC Docket No. EC96-19-000).

The Applicants requested authorization, pursuant to Section 203 of the Federal Power Act, to transfer operational control (but not ownership) of certain transmission facilities to the ISO. The application discussed the proposed governance and structure, the manner in which the ISO will operate, and the transmission access and pricing rules that will apply to service over the ISO grid. Many of the critical details, such as operating protocols, specific service agreements, tariff terms and conditions, and rate schedules under which the ISO will arrange transmission and ancillary services, have not been developed. For example, we expect that the Phase II filings at FERC will include detailed protocols explaining how the ISO will integrate intermittent generation and loads. Most such agreements, tariffs, and rate schedules, will require the FERC's approval. On August 15, this Commission filed supplemental comments on the application. We commented on ISO governance and structure issues, and included specific recommendations on other issues to be included in the Phase II filing. In August, we asked that FERC require the Phase II filings by the end of 1996 to ensure that the implementation date of January 1, 1998, could be met.

AB 1890 has significantly affected the timing of the FERC proceedings. The FERC directed the Applicants to file comments on how implementation of the legislation would affect their proposal and also to amend their applications accordingly. On October 7, a Joint Statement of Applicants and Indicated Intervenors on Implementation of California Legislation was filed with the FERC. The Statement explained that AB 1890 affects several aspects of the ISO proposal. First, it affects the access charge for transmission service that has been proposed in Docket No. EC96-19-000. Second, it affects the governance and organization of the ISO and the PX. Third, it expands the scope of the ISO's responsibilities, including immediate ISO participation in the FERC proceedings. Fourth, it requires direct access reciprocity within California.

On November 29, 1996, the FERC issued an order conditionally authorizing establishment of an ISO and PX, conditionally authorizing transfer of facilities to an ISO, and providing guidance on the Phase II filings. The FERC directed the Applicants and the ISO to file the Phase II portion of their restructuring proposal by March 31, 1997.

In its order, the FERC granted limited authorization to the Oversight Board's start-up functions (establish nominating/qualification procedures, determine the composition of the board representation, and initially select the ISO and PX governing board members). However, the FERC stated it could not accept a permanent role for the Oversight Board in the governance or operations of the ISO, or appellate review of ISO Board decisions, because those matters are FERC jurisdictional (FERC order, mimeo at pp. 50-55). Thus, the Oversight Board is expected to form and appoint board members for the ISO and PX. Thus established, the ISO would undertake filing those portions of the Phase II filing assigned to it by the FERC, such as conflict of interest standards for members.

II.A.3. Joint Application for Authority to Sell Electric Energy at Market-Based Rates Using a Power Exchange (FERC Docket No. ER96-1663-000.)

In their joint filing on April 29, 1996, Applicants proposed how prices should be determined for sales through the PX and the structure and governance of the PX. SDG&E and Edison filed a market power supplement to the application on May 29. On July 19, PG&E filed a PG&E-specific analysis of market power issues.

On June 13, we intervened at the FERC and informed the FERC that we would submit comments on the PX application after our review of parties' comments on Docket No. ER96-1663-000 submitted to the Commission. On August 15, the Commission filed comments with the FERC on several issues, including governance and structure of the PX board, the unbundling of spinning reserve and other ancillary services from the provision of energy by the PX, and the pricing of energy for the PX during over-generation conditions.(2) Applicants and other parties have filed comments in response to our recommendations.

II.B. Mandatory Buy-Sell

In the CCR, parties were asked to comment on the impacts, if any, of AB 1890 on the mandatory buy-sell requirement, whereby we required the investor-owned utilities to "bid all of their generation into the Power Exchange and satisfy their need for electric energy on behalf of their full service customers with purchases made from the Exchange" during the five-year transition period. (Preferred Policy Decision, p. 51 (mimeo).) Parties were also asked to provide additional detailed information supporting the benefits and detriments to California ratepayers of this requirement.

We received comments on the above issues from PG&E, Edison, SDG&E, the Office of Ratepayer Advocates (ORA), the California Cogeneration Council, Independent Energy Producers, and Watson Cogeneration Company (jointly, CCC), the California Large Energy Consumers Association and the California Manufacturers Association (jointly, CLECA), and the California Energy Commission (CEC). We received reply comments from Edison, SDG&E, CCC, and Enron Capital & Trade Resources. These parties uniformly concluded that our mandatory buy-sell requirement is not directly addressed by AB 1890, and is not in conflict with it.

Most parties support continuation of the requirement; some point out, however, that because AB 1890 calls for all or substantially all utility stranded costs to be recovered within 4 years (i.e., by December 31, 2001), the relevant time-frame for operation of the mandatory buy-sell requirement should now be 4 years, rather than the 5 years established by our policy decision.

PG&E and SDG&E, while basically supporting the requirement, present several suggestions for modifying it. PG&E takes the position that the requirement is consistent with the desire to see a viable market that would result in efficient energy prices to customers, and that such a requirement during the transition period is an appropriate way to achieve that result. However, PG&E argues that three modifications to the requirement should be granted. It first proposes that the Commission release it from the mandatory sell obligation when generation which is not designated as must-run will not be able to be dispatched by the PX. Next, PG&E requests that all generation which is contractually dispatched and marketed by third parties (operating under a generation bidding trust or some similar arrangement) be exempted from the mandatory buy-sell requirement. Finally, PG&E asks to be allowed to do some purchasing from outside the PX. PG&E does not specify just how much power it would purchase in this way, but states that this would provide a "tool to procure resources in a way which can be used more selectively to enhance UDC [utility distribution company] supply reliability." (PG&E's Comments to the CCR, p. 9.)

ORA and Enron continue to oppose the requirement. ORA raises many of the same issues it raised in its response to the applications for rehearing, namely: (1) that the requirement violates the Commerce Clause of the United States Constitution because no legitimate local interest has been identified, and no attempt has been made to assess alternatives; (2) that the requirement unnecessarily concentrates market power; (3) that it precludes beneficial transactions such as seasonal exchange with the Northwest; and (4) that it does not obviate the need for regulatory oversight, but increases it.

ORA believes that because AB 1890 allows utilities but not competitors to recover some going forward capital addition costs on a non-market basis, many utility competitors will be competing on the basis of short-run incremental costs, but investor-owned utilities will not be. This, ORA argues, will make price signals less reliable, because the PX will not reveal market short-term incremental costs as accurately as the Commission assumed it would. ORA also argues that the utilities have a built-in conflict of interest because they will have generator interests in the PX actions, as well as having to be concerned about minimizing costs to their customers. This will necessarily lead to the kind of strict regulatory oversight the Commission had hoped to minimize. ORA further argues that market power and buy-sell restrictions are related. ORA points out that AB 1890 makes it more difficult for bilateral providers to sell to smaller customers; thus the assumption that bilateral contracts are an equivalent substitute for the PX is subject to question.

Enron believes that implementation of the market structure mandated by AB 1890 is best accomplished without the imposition of a mandatory buy-sell requirement. Enron argues that the Commission should go a step farther than proposed by PG&E and question whether the requirement makes any sense at all anymore, given PG&E's position that so many exemptions from it should be granted.

We will not address legal issues raised by these parties, because we are not resolving the applications for rehearing here. We also will not address the alternatives posed by PG&E and SDG&E to the mandatory buy-sell requirement as we set it forth in the Preferred Policy Decision. These proposals are, in reality, requests to modify the Preferred Policy Decision, which we will not do in a roadmap decision. We conclude that the mandatory buy-sell requirement is not inconsistent with AB 1890. However, the operable period should end on December 31, 2001, consistent with the time-frame for recovery of most utility transition costs, pursuant to newly added Public Utilities (PU) Code § 367(a).

II.C. Market Power

Our Preferred Policy Decision emphasized our concern that incumbent utilities might be able to exercise market power in the restructured environment. Market power could undermine competition and negate the benefits to be derived from the new competitive framework. We found that isolating control of transmission in the ISO and establishing an independent dispatch ordering mechanism resulting in operational unbundling are two crucial features for effective mitigation of vertical market power. We continue to believe that vertical market power related to ownership of transmission can be effectively mitigated through the ISO and will carefully scrutinize the Applicants' Phase II ISO filings at the FERC to ensure that the ISO is independent and that vertical market power issues are adequately addressed.

As discussed in our Preferred Policy Decision, significant concerns regarding horizontal market power from concentrated ownership of generation units, and the resulting potential for anticompetitive behavior, may require the existing investor-owned utilities to divest themselves of a substantial portion of their generating assets. PG&E and Edison filed their initial divestiture plans with this Commission on March 19, 1996. In addition, as discussed above, as part of their application for market-based pricing authorization for the PX, PG&E, Edison, and SDG&E have filed horizontal market power studies at the FERC which assume PG&E's and Edison's voluntary divestiture of 50% of their fossil-fired generation.(3) This Commission is not only an active participant in this FERC proceeding, but is also committed to an ongoing examination of market power issues in its own proceedings. Because we are convinced that effective mitigation measures must be in place no later than January 1, 1998, in order to mitigate the potential exercise of market power, we have requested that the FERC schedule a series of joint technical workshops with this Commission on market power mitigation.

In response to the ACR on Divestiture, we held a prehearing conference on October 30, 1996, on the status of the PG&E and Edison voluntary divestiture plans. Subsequently, on November 15, PG&E filed its Section 851 application (Application (A.) 96-11-020) seeking Commission approval to divest four specific generation units it plans to sell to fulfill its voluntary divestiture of at least 50% of its fossil-fired generation.(4) On November 27, Edison filed its Section 851 application (A.96-11-046) seeking Commission approval to divest twelve specific generation stations that it plans to sell to fulfill its voluntary divestiture of at least 50% of its fossil-fired generation.(5) We are committed to processing these Section 851 applications as expeditiously as possible, in order to meet the January 1, 1998, date for the commencement of operations of the PX. Issues relating to locational market power of "must-run" units and any necessary mitigation measures will be addressed both before the FERC and before this Commission in the Section 851 divestiture proceedings.

We recognize that market power issues will overlap with other state proceedings, such as the generation performance-based ratemaking (PBR) proceedings (A.96-07-009 et al.), the transition cost recovery proceedings (A.96-08-001 et al.), and the direct access proceeding in this docket. For example, it is this Commission's position at the FERC that the ISO will determine which reliability services it requires to operate the system grid. However, state-side cost-recovery treatment of "must-run" units is an issue in the generation PBR proceedings. Further, the treatment given these units in these proceedings may affect their market values, which in turn will affect the transition cost calculations. As previously stated, this Commission is committed to an ongoing examination of market power issues in its own proceedings.

Independent System Operator and Power Exchange

II.D. Voluntary Divestiture

In the CCR, we provided the parties with an opportunity to address the impacts of AB 1890 on voluntary divestiture. (CCR, p. 5. ) We further requested that the parties provide additional comments on the issue concerning the adequacy of the 50% voluntary divestiture as a means for mitigating market power problems. We also asked the parties to provide comments on our divestiture incentive for "an increase in the rate of return on equity component of up to 10 basis points for each 10% of fossil generating capacity divested." (CCR, p. 5.)

AB 1890 did not affect our authority to move forward and address competition and market power problems along the lines set forth in the Preferred Policy Decision, including the proposal of voluntary divestiture as a means for mitigating such

problems. Moreover, the Legislature reaffirmed our role in addressing issues concerning competition, market power and divestiture with the enactment of PU Code Sections 330 and 362.(7) For example, in PU Code Section 330(l)(3), the Legislature found that we had properly concluded that:

"There is a need to ensure that no participant in these new market institutions has the ability to exercise significant market power so that operation of the new market institutions would be distorted."

Also, PU Code Section 362 spells out the relationship between divestiture and market power, by providing:

"In proceedings pursuant to Section 455.5, 851, or 854, the [C]ommission shall ensure that facilities needed to maintain the reliability of the electric supply remain available and operational, consistent with maintaining open competition and avoiding an overconcentration of market power." (Emphasis added.)

Although AB 1890 discusses our authority in addressing issues concerning competition, market power and divestiture, the legislation makes no specific reference to our voluntary divestiture proposal as a means of mitigating market power problems or to our incentive for encouraging such divestiture. Accordingly, as we move forward, AB 1890 does not affect the stance we took in implementing generation competition in our Preferred Policy Decision.

In having the parties address the impact of AB 1890 on voluntary divestiture, we also asked the parties to provide additional information in their comments concerning the adequacy of the 50% voluntary divestiture proposal and the incentive for divestiture. (CCR, p. 5.) Based on these comments, we have reached the following conclusions on these two issues.

II.D.1. 50 Percent Voluntary Divestiture

In the Preferred Policy Decision, we proposed that the utilities voluntarily divest at least 50% of their fossil-fueled generation assets in order to mitigate market power problems. (Preferred Policy Decision, p. 101 (mimeo).) In the CCR, the parties were asked to provide additional information as to the adequacy of this proposal. (CCR, p. 5.) Comments on this particular issue were filed by the following parties: Edison; PG&E; ORA; CCC; Center for Energy Efficiency and Renewable Technologies, Environmental Defense Fund and Natural Resources Defense Council (jointly, CEERT); CLECA(8); and Coalition of California Utility Employees (CCUE).

PG&E and CCUE suggest that we should take no further action on the proposal for 50% voluntary divestiture because the level of divestiture will ultimately be determined by FERC. (PG&E's Comments to the CCR, p. 3; CCUE's Comments to the CCR, pp. 1-2.) We reject this suggestion. As mentioned above, we are under a duty to consider and resolve, in the public interest, issues concerning competition, which include market power problems. (See Northern California Power Agency v. Public Util. Com., supra, 5 Cal.3d at 377-379; see also, Phonetele, Inc. v. Public Utilities Com. (1974) 11 Cal.3d 125, 131-132; Industrial Communications Systems, Inc. v. Public Utilities Com. (1978) 22 Cal.3d 572, 581-583; United States Steel Corp. v. Public Utilities Com. (1981) 29 Cal.3d 603, 609.) This duty, as it relates to electric restructuring, is part of our responsibilities to ensure that the rates for ratepayers and the practices or "methods of manufacture, distribution, transmission, storage, or supply employed" by the utility are just and reasonable. (See e.g., PU Code §§ 451 and 761.) Further, with the enactment of PU Code Sections 330(l)(3) and 362, this Commission's obligation for the purposes of electric restructuring has been further spelled out by the Legislature.

This duty did not cease with the issuance of the Preferred Policy Decision; rather, our consideration of issues relating to competition is ongoing, particularly in such proceedings involving divestiture, direct access and unbundling. Fulfillment of this duty in no way interferes with the jurisdiction of the FERC. (See Edison-SDG&E Proposed Merger [D.91-05-028] (1991) 40 Cal.P.U.C.2d 159, 178-180; see also, Northern California Power Agency v. Public Util. Com., supra, 5 Cal.3d at 378.)

In response to the CCR's inquiry concerning the adequacy of the proposal for 50% voluntary divestiture, ORA states that 50% is not adequate and recommends complete divestiture, as means for eliminating market power problems. (ORA's

Comments to the CCR, pp. 1-4.) In its comments, CCC indicated that Independent Energy Producers (IEP) "has long advocated requiring full divestiture of all utility generating assets in order to mitigate market power and continues to support full divestiture." (CCC's Comments to the CCR, p. 2.) Regardless of this position, IEP agrees that at a minimum, 50% divestiture of fossil generation is absolutely necessary. (CCC's Comments to the CCR, p. 2.)

Edison argues that it has "demonstrated that the divestiture of 50 percent of its gas-fired generation is more than adequate to dispel horizontal market power concerns associated with sales of energy by Edison to the PX." (Edison's Comments to the CCR, p. 2, citing its Report on Horizontal Market Power Issues submitted to the FERC on May 29, 1996, and filed with this Commission on May 30, 1996.)

The comments to the CCR have not persuaded us that AB 1890 requires us to modify our proposal for at least 50% voluntary divestiture of fossil generation assets. Based on what we know today and the comments from Edison and CCC, we are still convinced that this proposal, at a minimum, is adequate for the time being. With the proposal of at least 50% voluntary divestiture of fossil generation assets, we have a starting point which has allowed us to move forward with our examination of the market power issues relating to divestiture. (See generally, ACR on Divestiture; Prehearing Conference of October 30, 1996.)

Moreover, as we have discussed above, our consideration of the market power problems is ongoing. We recognized in the Preferred Policy Decision "the need for a rigorous empirical market concentration analysis to establish strong conclusions and to verify or disprove [a] suspicion" of excessive market concentration in electric generation. (Preferred Policy Decision, p. 99 (mimeo).) We also indicated:

"Even before the transition to competition begins,…market power analyses may present us with identifiable adverse impacts. We will act on the results of those studies after we have received and reviewed them." (Id. at p. 187 (mimeo).)

Accordingly, our review of the market power problems will continue, and our final determinations will be based on comprehensive analyses of these issues, as well as on other information we have and will have before us in the record on these issues.(9)

II.D.2. Incentive for Voluntary Divestiture

In our Preferred Policy Decision, we provided for an incentive of 10 basis points for each 10% fossil generating capacity divested. We received comments from Edison, PG&E, and ORA in response to the CCR on this matter. Edison indicated that the incentive would be sufficient only if "it applies to all utility-owned generation in the CTC account, not merely the CTC associated with fossil units." (Edison's Comments to the CCR, p. 3.) Edison also asked us to clarify that this is what the Preferred Policy Decision intended. (Edison's Comments to the CCR, p. 3.) Edison had made this same request in its Comments on Plan for Voluntary Divestiture, dated March 19, 1996, p. 21. PG&E asserts that at the rate of 10 basis points for every 10% of fossil generation divested, the requested 50% fossil divestiture would restore only a portion of the rate of return reduction, and thus the voluntary incentive is inadequate. (PG&E's Comments to the CCR, p. 5.) PG&E proposes at least "15 basis points of return, exclusive of tax effects, for every 10% of fossil generation divested." (PG&E's Comments to the CCR, p. 5.) ORA claims that the voluntary divestiture incentive is unnecessary and undesirable. ORA argues that we have the authority to order divestiture without the need to provide for "any incentive payment," and this "incentive payment" will increase Edison's and PG&E's rate of return on their CTC assets by 24 basis points. (ORA's Comments to the CCR, p. 6.) Further, ORA argues that the "mechanics of the divestiture incentive [will have] the unintended effect of skewing the utilities' decisions on which plants to divest," whereby they will divest older and more inefficient plants with the relatively larger transition cost rate base, and thus enhance their rates of return. (ORA's Comments to the CCR, pp. 6-7.)

At this time, we are not convinced by the comments that the voluntary divestiture incentive of 10 basis points for every 10% divested should be changed pursuant to AB 1890 or for any other reason. Although we are not persuaded by the comments to change or eliminate the incentive, we are not foreclosing further consideration of the issue during the divestiture proceedings, if warranted.

In response to Edison's request for clarification, the Preferred Policy Decision is very straightforward. It speaks about "an increase in the rate of return for the equity component of up to 10 basis points for each 10% of fossil generating capacity divested." (Preferred Policy Decision, p. 101 (mimeo), emphasis added.) Edison's request is essentially a request for modification. In this order, we do not address this requested modification. This matter is best addressed during our divestiture proceedings.

III. Consumer Choice Issues: Direct Access, Consumer Protection and Education, and Public Purpose Programs

III.A. Eligibility for Direct Access

In the Preferred Policy Decision, we gave the parties an opportunity "to recommend proposals for direct access, including eligibility parameters in the initial phase of direct access, consistent with the principles outlined for direct access and real-time and time-of-use rate options." (Preferred Policy Decision, pp. 65, 220 (mimeo).) The parties were also asked to carefully consider whether a minimum phase-in schedule was necessary or whether eligibility can be held open to all electricity consumers sooner than five years, or perhaps after the twelve-month initial phase. (Id. at pp. 66, 221 (mimeo).)

In absence of an agreement between the parties for an earlier implementation of direct access, we proposed a "default schedule"—namely, a minimum five-year phase-in, commencing no later than January 1, 1998. (Id. at p. 65 (mimeo).) The Commission also set forth a schedule for phasing in direct access for Edison, PG&E and SDG&E. (Id. at pp. 66, 220 (mimeo).) This included an 800 MW participation limit for Edison and PG&E, and 200 MW participation limit for SDG&E. (Id.) We also adopted, as a reasonable eligibility parameter, an 8 MW threshold limit to be applied to individual customers and aggregated customer groups for the initial phase. (Id. at p. 68 (mimeo).)

AB 1890 is in accord with our view that meaningful competition will result from direct access. PU Code Section 330(k)(2) states: "In order to achieve meaningful wholesale and retail competition in the electric generation market, it is essential to . . . [p]ermit all customers to choose from among competing suppliers of electric power." Further, AB 1890 reaffirms the Preferred Policy Decision's determination that direct access should commence by January 1, 1998. PU Code Section 330(n) states, "Opportunities to acquire electric power in the competitive market must be available to California consumers as soon as practicable, but no later than January 1, 1998, so that all customers can share in the benefits of competition."

Although provisions in AB 1890 concerning implementation of direct access are generally similar to requirements in our Preferred Policy Decision, the legislation affects the time-frame of the "default schedule." The "default schedule" requires that direct access be completed by January 2003. (Preferred Policy Decision, pp. 66, 220 (mimeo).) AB 1890 provides that any phase-in shall be completed "for all customers by January 1, 2002." (PU Code § 365(b)(1).) Thus, this "default schedule" at a minimum is shortened. As a result of the shortening of the time, other aspects of the "default schedule," e.g. total number MW available for participation and threshold limitations for eligibility, may be affected.(10)

Furthermore, this "default schedule" may no longer be necessary, because the utilities themselves are recommending a different approach. PG&E and Edison have proposed a faster schedule than the "default schedule." (Joint Comments of PG&E and Edison to the August 30, 1996 Report of the Direct Access Working Group (DAWG), filed September 30, 1996, p. 3; see also, PG&E's Reply Comments to the JACR, filed October 15, 1996, p. 3; Edison's Reply Comments to the JACR, filed October 15, 1996, p. 2.) SDG&E believes there should be no phase-in. (SDG&E's Reply Comments to the JACR, filed October 15, 1996, pp. 3-5.)

Our discussion today concerning the phasing-in of direct access does not constitute a final determination as to how we will order implementation of direct access. Issues related to direct access, such as whether a phase-in is necessary, or if there is a phase-in program, how it will be done, will be addressed in a future decision, as discussed below. Our objective in this order is merely to explain how AB 1890 has impacted our Preferred Policy Decision in this particular area of direct access.

III.B. Registration

In the Preferred Policy Decision, we stated that as part of our consumer protection role, we would consider a program to register or license energy service providers, including marketers, brokers and aggregators. (Preferred Policy Decision, p. 188 (mimeo).) AB 1890 mandates this registration requirement for energy service providers offering electrical service to residential and small commercial customers within the service territory of an electric corporation, but limited the requirement for the registration of brokers. AB 1890 states: "It is the intent of the Legislature to protect the consumer by requiring registration of certain sellers, marketers, and aggregators of electricity service, requiring information to be provided to consumers, and proving for the compilation and investigation of complaints."(11) (AB 1890, § 1(d).) Brokers are not mentioned in this legislative intent; however, if a broker is an aggregator, as defined by PU Code Section 331(a), this broker must register. Thus, AB 1890 mandates a registration program that our Preferred Policy Decision contemplated, but differs from our proposed program in not requiring brokers who are not aggregators to register. (See PU Code §§ 394-396.)

Further, AB 1890 requires the registration of sellers of electricity services, and aggregators who are public agencies, cities, counties, or special districts that offer electrical services to residential and small customers within the service territory of an electric corporation. (See AB 1890, §1(d); PU Code §§ 330(a) and 394(a).) Registration of these particular entities was not contemplated in the Preferred Policy Decision.

III.C. Direct Access and Consumer Protection and Education Procedural Issues

The Commission provided for customer choices in its Preferred Policy Decision.(12) Pursuant to Commission direction, DAWG filed two reports.(13) "Design and Implementation of Direct Access Programs" was filed on August 30 and addresses numerous issues to be considered in the implementation of direct access. Comments on this first report were filed on September 30 with reply comments filed on October 15. On October 10, prior to the filing of the reply comments, the assigned Commissioners conducted a public hearing to take comments on issues identified for initial resolution in the Working Group's report. By ruling, the assigned Commissioners asked that parties address the implications of AB 1890 on the implementation of direct access and consumer protection/education in their October 15 written reply comments. Most recently, the assigned Commissioners issued a ruling on December 9, 1996, which directed PG&E, SDG&E, and Edison to submit a report by January 17, 1997, on the communications and data systems required to support the functions of the PX, ISO, schedule coordinators, and direct access providers. Comments on this report are due by January 24, 1997. We anticipate that the report may assist the utilities and the ISO in preparing their Phase II filings at the FERC and could also serve as the basis for this Commission's comments on those filings. We encourage interested parties to participate in discussions held by the Trust Advisory Committee to ensure that their views are considered.

"The Direct Access Working Group Report on Consumer Protection and Education in a Restructured Electric Industry" was filed on October 30. This report discusses the options to be considered in implementing consumer protection and education programs. Much like the first report, this second report identifies those issues which require further Commission guidance in the near future in order to develop a comprehensive critical path for the implementation of direct access and consumer protection/education. Initial comments on this report were filed on November 26 with reply comments filed on December 11.

Many parties have agreed that we must first address threshold issues which impact the manner in which we and the stakeholders consider other related issues. Examples of threshold issues are direct access eligibility/phase-in and the use of load profiling and interval metering to measure customer usage. We anticipate addressing these threshold issues in a decision to be considered in February 1997. These threshold issues can be defined as Track 1 issues. The Track 1 decision will identify issues for further consideration in Track 2 and the appropriate procedural mechanisms by which to address them. There may well be remaining issues to address in the direct access issue area. While we cannot identify these issues with particularity at this time, it is prudent to set a schedule which accommodates the possibility that there will be residual issues to be addressed after the Track 2 decision.

As stated in our previous Roadmap Decision, consumer protection and education measures must be in place well before the transition period begins. Coordination between the low-income issue area and the consumer protection and education issue area is essential. Based on principles and guidance provided in either the Track 1 decision or a subsequent ruling, parties will have the opportunity to file suggested rules on consumer protection and education programs in March 1997. We expect that the Track 1 decision will include consideration of the independent education trust and the consumer education program.(14) Further consideration of these programs may include the coordinated efforts of both DAWG and the Low-Income Working Group. At a minimum, we continue to recognize the need for participation of consumer advocates and other parties involved in the Low-Income Working Group, particularly when considering issues related to consumer protection and education. Based on parties' suggested rules, we will issue proposed rules for comment. These proposed rules along with the Track 2 issues will be decided in a decision anticipated in May 1997.

We have recognized the value of stakeholders working together to gain a common understanding of issues, to narrow and focus critical issues, and to reach possible consensus on resolution of those issues. We will continue to rely on the efforts of the stakeholders by directing PG&E, SDG&E and Edison to file and serve preliminary tariffs in June 1997. These preliminary tariffs should reflect the issues addressed by the Track 1 and 2 decisions. Workshops or other forums will then be established to provide an opportunity for parties to discuss these preliminary tariffs. Because we expect that the same tariffs will be affected by the decisions made in the unbundling/ratesetting issue area, we ask for preliminary filings in both of these issue areas which will allow parties to coordinate their efforts. Further direction on this filing will be given in the Track 2 decision or subsequent ruling. Direct access tariffs, to become effective January 1, 1998, must be approved by October 1997 in order to provide sufficient time for market participants and customers to consider their choices in electric services. While all aspects of the tariffs may not be known at that time, it is important to ensure that the general framework of these rules are in place prior to the beginning of the transition period.

As with many of the issue areas in this proceeding, there are numerous interrelationships and linkages which must occur in order to ensure a smooth implementation of the new market structure. In considering the implementation of phase-in and eligibility parameters, if any, we must be aware of the CEC's certification process as required under PU Code Section 383. The CEC is responsible for developing

certification procedures for renewable resource providers. At the same time, pursuant to PU Code Section 365, this Commission is responsible for developing guidelines for customers who take at least 50% of their energy from renewable providers to bypass any phase-in for direct access. In addition, the issue of unbundling, particularly unbundling utility revenue cycle services will further define the implementation of direct access and consumer education efforts. We will also consider any potential for market power abuse as we move to this new market structure. This will include a consideration of the current rules on utility affiliate transactions and access to customer information.

Direct Access

III.D. Public Purpose Programs

In our Preferred Policy Decision, we determined that the need for activities performed in the public interest would continue as we moved towards a competitive framework, but the role of electric utilities as the providers of these services was less clear. We proposed certain policies and requested that working groups convene to provide us with additional information and recommendations to implement the policies we had proposed. Those reports were submitted in August, September, and October 1996.

AB 1890 provided additional legislative guidance in the areas of renewables, energy efficiency, research, development and demonstration (RD&D), and low-income programs and assigned certain areas to the responsibility of the California Energy Commission. The assigned Commissioners have explicitly sought comments from the parties on how our review of these issues is changed by AB 1890 and have adjusted the review process accordingly. In addition, this Commission and the CEC are working cooperatively to develop clear jurisdictional responsibilities and to jointly ensure effective implementation procedures.

Preliminary threshold issues were identified in a ruling issued on October 24, 1996 and discussed at a prehearing conference held on November 7. No party has requested that we hold evidentiary hearings on threshold issues in our public purpose proceeding. While the following schedule identifies our goals for decision dates, Phase 2 of this proceeding will be significantly affected by the threshold issues decided in Phase 1. Phase 2 activities may therefore be completed sooner or later than identified in the table. In addition, one of the threshold issues addressed in Phase 1 relates to funding levels greater than the minimum specified in AB 1890. Parties should be aware that our decision on funding levels for public purpose programs must be incorporated into the decision-making process in the ratesetting/unbundling proceeding, in order for public purpose program costs to be identified on customer bills.

Public Purpose

IV. Ratesetting Issues

The ratesetting issue area is an all-encompassing category that must necessarily underlie our move to a more competitive framework. The steps in ratesetting have not changed; that is, we will still be determining the rate components, revenue allocation, and rate design necessary to derive a rate for each customer class. However, we will be going about this process in a different way, particularly with respect to the rate freeze. The purpose of the ratesetting track, then, is to review our current ratemaking practices and to consider necessary revisions to these practices to accommodate the short-term and long-term changes in the electric industry necessary for implementation of AB 1890 and the new market structure beginning in 1998. This track incorporates unbundling of rates, transition costs, performance-based ratemaking, and other activities that affect rates and revenue requirements.

Historically, we have operated under the rate case plan, including triennial general rate cases (GRCs) and annual Energy Cost Adjustment Clause (ECAC) proceedings. The Electric Revenue Adjustment Mechanisms (ERAM) is addressed in GRC and ECAC proceedings. ECAC and ERAM balancing accounts protect the utilities against certain changes in costs and sales forecasts and guarantee recovery of some of their costs through these balancing accounts. ECAC proceedings have typically combined consideration of fuel and purchased power expenses with updating and adjusting the utility's authorized revenue requirement due to changes such as cost of capital, ERAM adjustments, and consolidating rate and revenue changes from prior Commission decisions.

With the creation of the PX by January 1, 1998, and the requirement that the utilities purchase all supplies from the PX, the need to establish a forecast ECAC revenue requirement may be reduced. However, we must continue to have access to the information about the utilities' generation costs and revenues from the PX in order to monitor PX costs billed to customers and properly debiting or crediting the transition cost balancing account. Furthermore, ECAC reasonableness reviews will continue for the interim time period, at least until the utilities' fuel procurement practices are no longer undertaken in a regulated regime. Reasonableness reviews are the quid pro quo of balancing account treatment. Once the PX is functioning, we are hopeful that the incentives provided by the marketplace will begin to take the place of this regulatory practice. Some form of review and verification will still be necessary after the new market structure is in place to verify the accuracy and fairness of the utilities' recovery of PX costs.

In our continuing effort to streamline our ratemaking procedures and practices, and to ensure that our regulatory goal of establishing fair and reasonable rates for the regulated portion of utility operations and services is achieved, we will establish a separate proceeding to consider ratemaking issues related to each electric utility's revenues. This Revenue Adjustment Proceeding (RAP) will consolidate all pending revenue changes, and track utility revenues at present rate levels for the purpose of comparison with authorized amounts. This proceeding will also address future revenue allocation and rate design issues that are currently being addressed in the unbundling proceeding.

The RAP will be a new proceeding designed to annually review, track, and compare each utility's authorized revenue requirements with the actual recorded revenues and to make any necessary adjustments or updates due to the authorized revenues for PBRs, various power purchase contracts, public purpose programs, nuclear facilities, nuclear decommissioning, transition costs and other proceedings. The authorized revenues will be established in their respective proceedings and consolidated into the RAP; therefore, this proceeding will require information from many proceedings. The first RAP will begin in 1998. Additional procedural guidance will be provided for this new proceeding.

IV.A. Unbundling Issues

In D.96-10-074, we directed PG&E, Edison, and SDG&E to provide a cost separation of transmission and distribution for both rate base and base rate revenue requirement. This information is based on the separation of transmission and distribution (T&D), which was adopted by the FERC on October 30.(15) D.96-10-074 also asked the utilities and parties to comment on several issues related to metering and billing services. Parties and utilities are further asked to provide their estimates of incremental cost of metering and billing given the objective and strategies laid out in the decision. (See D.96-10-074, pp. 12-18 (mimeo).)

Given the nature of this subject area, we expect to conduct evidentiary hearings. Therefore, our proposed schedule is designed to accommodate hearings within the target implementation date of January 1, 1998.

IV.A.1. Coordination with other proceedings

Close coordination between this proceeding and the transition cost proceeding is critical to ensure the efficient flow of information necessary for calculation of the competition transition charge (CTC). Similar coordination is essential between this proceeding and direct access to support implementation of direct access.

AB 1890 authorizes a cost recovery strategy that freezes rates at levels in place as of June 10, 1996, and lowers rates for residential and small commercial customers by at least 10%, beginning in 1998. Under the rate freeze, total rate levels are fixed. Thus, the sum of all rate components such as generation, transmission, distribution, CTC, and public purpose charges, cannot exceed the frozen rate level. Generally, the utilities have recommended that CTC be calculated residually, that is, as the difference between the frozen rate level and all other authorized rate components. The result is that the CTC will be a residual of the frozen rate minus transmission, distribution, nuclear decommissioning, public goods and PX energy charges and, for residential and small commercial customers, possibly a financing surcharge.(16) Because the PX price will vary with time, determination of the CTC for direct access customers requires the PX price. Parties in the transition cost proceeding (A.96-08-001 et al.) have stated that the residual calculation of CTC rates for direct access customers will be based on actual, recorded PX rates. This methodology will be further developed in the unbundling applications, filed on December 6. (See TR at 25 in A.96-08-061 et al.)

The schedule we set forth today is designed to accommodate interim decisions like the Phase I Transition Cost decision. Parties should consider any relevant impacts of the Phase I Transition Cost decision in their briefs on unbundling. In addition, a portion of the rates will recover the cost of public purpose programs. The threshold decision in the public purpose issue area is anticipated in February 1997. We ask the parties to incorporate the impact of this threshold decision in their briefs as well.

As described in the Direct Access section, in order to ensure that adequate time is given to review tariffs, we will require the utilities to update their tariff filings in

June 1997. Following submittal of these updates, we will convene workshops to review the tariffs. This process will allow parties, after filing their briefs and replies, to examine the tariffs before final tariffs are filed in October 1997.

Unbundling

IV.B. Unbundling Utility Revenue Cycle Services

As stated above, D.96-10-074 asked PG&E, SDG&E and Edison and other parties to provide their estimates of incremental cost of metering and billing and to comment on other issues related to meter ownership, data access, meter installation, the potential extent of competition in metering and billing, billing consolidation, and the impact of standardization of communication protocols for meters. In D.96-10-074, we stated:

"Without factual inquiry, we do not know if various parties are right when they assert that the failure to separately charge for such "revenue cycle" activities will result in an absence of meaningful direct access opportunities for residential and small business customers. However, it is possible that such costs will be a proportionately greater share of the cost of serving smaller-volume customers and that if these costs remain fixed, there will be less of an opportunity for a firm to profit while providing service at a competitively attractive price. For these reasons, we remain concerned [that] unbundling certain "revenue cycle" costs by January 1, 1998, could affect the provision of direct access opportunities to residential and small business customers." (D.96-10-074, p. 8 (mimeo).)

While we raised these issues in the context of unbundling, we stated that further unbundling of certain services such as utility revenue cycle services(17) may have implications for direct access. The DAWG, in its August 30 report, discusses many of the issues described in D.96-10-074. Many parties, in their comments to that report, take positions as to whether further unbundling of these services should be accomplished by January 1, 1998, or deferred.

It is essential to ensure that the efforts of all the parties and Commission staff are coordinated efficiently. Segregating the unbundling of these utility revenue cycle services from both direct access and the unbundling/ratesetting issue areas will allow us to move forward expeditiously on these issues without delaying the schedules of the direct access and unbundling/ratesetting issue areas.

We will therefore establish a separate track for considering the policy issues raised in D.96-10-074 and parties' comments on those issues. The initial focus of this track is to determine whether, and if so, to what extent, there should be unbundling of services, in particular metering and billing services, by January 1, 1998. Issues related to metering, such as ownership, data access, installation, and standardization, will be dealt with in this separate track.(18) This track will also address issues related to billing, for example, bill consolidation. Determination of costs associated with metering and billing services will be addressed in the unbundling/ratesetting issue area. The need for coordination between these issue areas will obviously continue. We anticipate that at some point before January 1, 1998, these issue areas will reconverge.

Unbundling Revenue Cycle Services

IV.C. Performance-Based Ratemaking

IV.1. Ongoing Performance-Based Ratemaking Mechanisms

Prior to adoption of our Preferred Policy Decision, we adopted several PBR mechanisms. In the Preferred Policy Decision, we stated that these mechanisms would continue as approved until the transition to a new restructured electric industry has taken place. We are currently monitoring the experimental PBR mechanisms that were adopted and will review them as previously established in prior decisions.(19)

IV.C.2. Generation PBRs

Pursuant to assigned Commissioner rulings, PG&E, Edison, and SDG&E filed applications for approval of generation PBRs on July 15, 1996 (A. 96-07-009, A.96-07-010, and A.96-07-018, respectively). An ACR consolidated these applications and two phases have been established for this proceeding. The first phase will cover common issues and phase 2 will cover utility-specific issues. Parties have asked us to address our role and the roles of the FERC and ISO with regard to reliability generation units and to specify proceedings and procedural vehicles for resolution of threshold issues, including those related to reliability generation. We will address these issues in an upcoming decision or by subsequent ruling.

Generation Performance-Based Ratemaking

IV.C.3. Distribution PBRs

A June 21 ACR deferred the filing of distribution PBRs until the FERC's decision on the T&D separation. Now that the FERC has issued its decision on these issues, we will require the utilities to file their distribution PBR applications in early 1997. A scoping workshop will be scheduled in January 1997 to establish a schedule for these applications.

The distribution revenue requirement determined in the unbundling proceeding will be used to establish benchmarks in the distribution PBRs. Our rulemaking (R.96-11-004) on electric service quality, reliability and safety standards and the AB 1890 requirement to establish inspection, maintenance, repair and replacement standards must also be coordinated with and incorporated in the distribution PBRs.

Distribution Performance-Based Ratemaking

IV.C.4. Ratemaking Treatment for Nuclear Generating Assets

In D. 96-01-011 and D. 96-04-059, we adopted an incentive ratemaking treatment for SONGS. In the Preferred Policy Decision, we directed Edison and PG&E to file applications for incentive ratemaking treatment for the Palo Verde and Diablo Canyon nuclear generating stations, consistent with the ratemaking treatment adopted for SONGS. A.96-02-056 and A.96-03-054 were filed on February 29 and March 29 for Palo Verde and Diablo Canyon, respectively. On November 15, parties in the Palo Verde proceeding filed a Settlement Agreement. On November 26, 1996, the ALJ issued a proposed decision recommending approval of the settlement.

In. D.96-01-011, we adopted an incentive ratemaking treatment for SONGS that accelerates the recovery of the SONGS investment over an 8-year period (1996-2003) at a reduced rate of return and provides an Incremental Cost Incentive Pricing (ICIP) for the operating costs over the same time period. AB 1890 now provides specific guidance for the ratemaking treatment of Palo Verde and Diablo Canyon nuclear facilities: PU Code Section 367 shortens the time for the recovery of the utilities' nuclear investments to the period of the rate freeze or until the authorized transition costs are fully recovered. Section 368(d) removes for SONGS the limitation established in D.96-01-011 on the maximum amount of cost recovery that can be collected in any year, and shortens the recovery period. Section 367(a)(4) authorizes the ICIP prices over the 8-year period. These provisions, however, do not apply to Palo Verde and Diablo Canyon. Therefore, for these plants, the recovery of these nuclear investments and the ICIP prices are limited to the period of the rate freeze or until the authorized transition costs are fully recovered.

Newly-added PU Code Section 379 also authorizes a nonbypassable charge for nuclear decommissioning costs, until those costs are fully recovered. These costs and revenue requirements are traditionally determined in the GRC proceedings. In D.95-07-055, we established the investment guidelines for decommissioning trust funds and reporting requirements for determining these costs. One of those requirements is that engineering cost studies and ratepayer contribution analyses continue to be performed every three years. In the absence of GRCs, we will establish a Nuclear Decommissioning Costs Triennial Proceeding (NDCTP) to determine the decommissioning costs and establish the annual revenue requirement and attrition factors over the three year period. Once the annual revenue requirement is established in the NDCTP, the nuclear decommissioning charge will be established in the unbundling and ratesetting issue areas. Additional procedural guidance will be forthcoming.

In the Preferred Policy Decision, we highlighted the importance of maintaining adequate funds to cover the cost of nuclear decommissioning and therefore adopted a policy by which we would continue to oversee and monitor the existing trust funds. That policy is unchanged. PG&E, Edison, and SDG&E must continue to comply with the guidelines and reporting requirements as set forth in D.95-07-055. Any requests to modify those guidelines must be made through petitions for modification of that decision. Any requests to accelerate the recovery of these costs must be made through a formal application.

The treatment of the utility nuclear generating assets is closely linked both to the transition cost proceedings and to the utilities' Cost Recovery Plans (CRPs). Transition costs resulting from these assets are a significant component of the total transition cost amount; therefore the coordination of these proceedings is critical. Determining the authorized ICIP prices and the amount of nuclear investment a utility can amortize over the rate freeze period are required steps in order to determine the authorized revenue requirements for each utility and the level of transition costs for each year. We will use the transition cost proceedings to develop a record to establish the guidelines for computing the transition costs on an ongoing basis and a mechanism for tracking the amount of transition costs and revenues recovered each year for the nuclear facilities, based on actual recorded data. This information is critical in determining when the nuclear facilities are fully amortized.

IV.D. Transition Costs

In the Preferred Policy Decision, we define transition costs as the net above-market costs associated with uneconomic assets. Uneconomic assets are those assets whose book value exceeds market value. Transition costs arise from generation assets, nuclear power plant settlements, power purchase contracts, regulatory assets, and the reasonable costs of early retirement or retraining programs. AB 1890 adds Sections 367-377 to the PU Code which specifically define and address transition costs.

Our objective in this area continues to be the collection of transition costs in a manner that is competitively neutral, fair to various classes of ratepayers, and does not increase rates. As discussed in our Preferred Policy Decision, and required by Sections 367 and 370, in order to achieve that objective, we will institute a nonbypassable charge, the CTC, for all retail customers, whether they continue to take bundled service from their current utility or pursue other options. Our methods for valuing transition costs will rely on market mechanisms to the extent possible, and will seek to minimize these costs.

Pursuant to AB 1890, the calculation and collection of most transition costs must be completed by March 31, 2002. Exceptions include transition costs arising from SONGS, which shall be collected until 2004; costs arising from transition obligations to utility employees, which may be collected through 2006; and costs associated with purchased power contracts, which will, for the most part, be collected for the duration of the contract or until the contract is restructured.

In order to record the transition costs for these assets, each utility must establish a transition cost balancing account. This account will track the calculation and collection of transition costs, both on an ongoing basis and at the time of market valuation, as described in our Preferred Policy Decision. As discussed below, interest on the balance of transition costs associated with investment in uneconomic generating assets will reflect a lower rate of return, in keeping with the reduced risk associated with recovery of the investment in these assets.

IV.D.1. 90% Return on Equity

In the Preferred Policy Decision, we adopted "90% of the embedded cost of debt as a reasonable rate of return on equity . . . to reflect the reduced risk" associated with the accelerated depreciation of the generation assets that is part of our recovery of transition costs. (Preferred Policy Decision, pp. 111 and 123-124 (mimeo).) In the CCR, the parties were asked to "address the positive and negative aspects of this reduction, and to consider impacts, if any, AB 1890 might have had on this reduced rate of return on equity." (CCR, p. 6.)

ORA and TURN argue that that with the passage of AB 1890, the utilities' risk of recovery of costs associated with stranded generation assets should be further reduced from what it was in the Preferred Policy Decision. (ORA's Comments to the CCR, pp. 13-14; TURN's Comments to the CCR, pp. 1-3.) ORA asserts that AB 1890 has "codified the recovery of transition costs into law," and the rate reduction bonds have removed uncertainty for recovery of stranded assets because the utilities will receive an upfront payment for stranded costs which would have been recovered over five years under the Preferred Policy Decision. (ORA's Comments to the CCR, pp. 13-14.) TURN expressed similar arguments. (TURN's Comments to the CCR, pp. 1-2.) TURN also contends that utilities' risk is further reduced because AB 1890 provides for a rate freeze and transfers ECAC and ERAM overcollections to transition cost recovery. (TURN's Comments to the CCR, pp. 2-3.) For these reasons, ORA and TURN argue for an even lower return on equity than provided in the Preferred Policy Decision.

Edison and PG&E argue that AB 1890 would justify a higher return on equity associated with transition costs for utility generation-related assets. (Edison's Comments to the CCR, pp. 11-12; PG&E's Comments to the CCR, p.10.) Edison and PG&E contend that AB 1890 increases the risk of nonrecovery of transition costs significantly above the level that existed under the Preferred Policy Decision; this is because the legislation has shortened the period for collecting these costs. (Edison's Comments to the CCR, p.11; PG&E's Comments to the CCR, p. 10.)

However, despite these arguments for a higher return on equity, Edison states its willingness "to accept the return on equity as set forth in the Preferred Policy Decision and does not propose that [we] now reopen this determination. . . ." (Edison's Comments to the CCR, pp. 11-12.) Further, PG&E asserts that AB 1890 has confirmed the return set forth in the Preferred Policy Decision. (PG&E's Comments to the CCR, p. 10, citing to PU Code § 367(d).) Consequently, PG&E says that it has "proceeded with implementation filings which assume that the '90% of embedded cost of debt' applies to fossil fueled plant investments and to the recovery of Diablo Canyon sunk costs using a SONGS-like rate recovery treatment." (PG&E's Reply Comments to the CCR, p.2, fn. 2; see also, PG&E's Comments to the CCR, p. 10.)

In its comments, SDG&E states that "the Preferred Policy Decision's reduction of return on equity associated with generation facilities is appropriate," because it "reflects two basic principles that were articulated in the Preferred Policy Decision – it provides a proper incentive for utilities to minimize transition costs and it benefits ratepayers." (SDG&E's Comments to the CCR, p. 6.) Further, like PG&E, SDG&E contends that "AB 1890 adopts the level of reduction of the return on generation set forth in the Preferred Policy Decision." (SDG&E's Comments to the CCR, p. 6.)

After reviewing all the comments on this issue, we are not persuaded that the return on equity set forth in the Preferred Policy Decision needs to be further reduced or increased. We are not convinced that the risks have changed so significantly with the enactment of AB 1890 to warrant any such change. Further, we agree with SDG&E that the 90% of the embedded cost of debt as a reasonable rate of return on equity "is appropriate." We continue to believe that it will provide the right incentive for utilities to minimize transition costs, and thus, ratepayers will benefit.

Further, we agree that AB 1890 confirms the rate of return on equity we adopted in the Preferred Policy Decision. PU Code Section 367(d) states, in pertinent part: "Recovery of costs prior to December 31, 2001, shall include a return as provided for in Decision 95-12-063, as modified by Decision 96-01-009, together with associated taxes."

IV.D.2. Transition Cost Procedural Issues

Such issues as establishing the balancing account and quantifying the transition costs for 1998 will be addressed in the transition cost proceeding, A.96-08-001 et al., which must necessarily be completed before January 1, 1998. In Phase I we address CTC terms and conditions, CTC exemptions, and details associated with the creation and maintenance of the transition cost balancing account. We will also consider market rate forecasts (or a market proxy for the PX clearing price) in order to compute ongoing transition costs and to establish the level of transition costs to be collected for 1998. The actual charge (or CTC component of rates) for customers will be determined residually in the ratesetting issue area.

Phase II will focus on both the factual and policy underpinnings of the quantitative aspects of establishing transition costs. This includes reviewing eligibility and costs associated with the elements included in the transition cost requests and assumptions used in the estimates (e.g., forecasted prices and sales and discount rates).

One important aspect of Phase II will include crediting the beginning balance to the transition cost balancing account (i.e., determining the level of unrecovered investment that is provided transition cost treatment by the Preferred Policy Decision and AB 1890). This will also include making a determination on transition costs associated with regulatory assets and obligations. Phase II issues will address methods of truing up any forecasts with actual recorded data.

The table below indicates the procedural schedule for addressing transition costs. It is important to note that our work on Phase II is already underway in the form of an independent audit of the utilities' transition cost filings. The audit is being performed by Mitchell and Titus, LLP, and will contribute in two major ways to our Phase II deliberations. First, the audit will evaluate utility estimates of net book value. Second, the audit will evaluate utility calculations of "going forward" transition costs that have yet to be incurred. Although the audit is unlikely to resolve all of parties' concerns, particularly regarding the going forward costs, it will prove a useful starting point for testimony on these issues.

There are two critical linkages between the transition cost proceeding and other proceedings. First is the interim decision to be issued in April 1997. This interim decision will provide information on transition cost balancing account mechanics and market rate forecasts that may be useful for developing pro-forma tariffs in the direct access arena. Second is the final decision goal date of October 22, 1997. The date for the final decision resolving Phase II issues ensures that the estimated level of transition costs for 1998 is in place, to the extent that estimate is necessary as we move forward to January 1, 1998.

We anticipate that additional steps will be necessary to establish the specific methodology to record transition costs arising from assets as they are divested or market valued through appraisal, and also to establish details associated with the appraisal market valuation methodology. However, these issues are not critical to implementation of direct access in 1998, and may therefore be placed in a Phase III to be conducted within a reasonable time frame. The timing of issues related to reasonableness reviews of capital expenditures made after December 20, 1995, do not appear to be critical to implementation but will be addressed in future rulings.

Transition Costs

IV.E. Rate Reduction Bonds

AB 1890 calls for issuance of rate reduction bonds through the California Infrastructure and Economic Development Bank (CIED Bank). The utilities are to file the initial applications for financing authority at this Commission and the CIED Bank by June 1, 1997, and we are required to complete our review of these applications within 120 days. Amounts financed through the bonds will be transition cost amounts identified by the time of request for the financing authority. We have already derived sunk costs (identifiable transition costs) associated with SONGS in D. 96-01-011 and D.96-04-059, a portion of which might be financed through the rate reduction bonds for Edison and SDG&E. More transition cost amounts for Edison will be identified in our decision on new ratemaking for Palo Verde. Our expected procedural schedule for Diablo calls for a final decision in March 1997, which will provide identifiable transition costs for PG&E.

As discussed above, AB 1890 requires the utilities to implement at least a 10% rate reduction for residential and small commercial customers by 1998. The utilities might seek to utilize rate reduction bonds to finance a portion of this rate reduction. We will conduct a workshop prior to the filing of the rate reduction bond applications. Details of this workshop will be provided in a future ruling. In any event, the results of our review of the applications for financing authority must be made available to the ratesetting proceeding so that the overall rate impacts can be evaluated in light of the rate freeze and so that the CTC can be derived as the residual of other rate components, as discussed above. The legislatively mandated time limit for completion of Commission review of applications for financing authority will ensure that this information can be made available to the ratesetting proceeding in a timely manner.

Rate Reduction Bonds

V. Reliability

It is crucial that California's utility customers are assured of a high degree of reliability in their electric service during and after the transition to a more competitive electricity market. In restructuring the electric services industry, we must consider our programs to date, as well as the most recent direction from the Legislature. AB 1890 emphasizes the need for reliability in the electric system through provisions affecting the ISO as well as this Commission. In addition, the legislation declares a state policy that California enter an interstate compact with other western states to allow enforcement of reliability standards on the region's utilities.

Reliability, as well as system safety, is the result of many different activities: 1) system operations, 2) maintenance and repair, and 3) system planning. In considering system operations, the operator must use system resources carefully, meeting demand for electricity by adding and subtracting system resources, and taking account of transmission constraints and other problems. In terms of maintenance and repair, the operator can respond only when system resources are fully available; moreover, poor maintenance can cause system outages due to the failure of crucial equipment. System planning is essential because generating, transmission, and distribution equipment can't be used unless it is first built or purchased, with enough lead time to meet new demand.

We have recently pursued several paths in order to improve and ensure reliability, concentrating on maintenance and repair. In 1994, we issued Investigation (I.) 94-06-012 on tree trimming rules for electric utilities, leading to D.96-06-012, which adopted new, interim standards. Our investigation of outages following severe storms in the PG&E service area produced D.95-09-073, which led to two further decisions. The first, D.96-09-045, established standards for overall system reliability, using measures of the duration and frequency of outages. The second, D.96-11-021, proposed enforceable standards for inspection of utility equipment and associated record-keeping. D.96-09-097 revised Commission standards for tree-trimming, designed to insure public safety and system reliability. Finally, R.96-11-004 was issued to consider rules for enforceable standards for safety and reliability. AB 1890 addresses reliability of the transmission system, the ISO, and the utilities' distribution systems. Careful coordination and Commission oversight are critical components of ensuring that system reliability standards are upheld.

In a broader sense, reliability has always been central to our mission. Major new generation or transmission plant additions have required a certificate of public convenience and necessity (CPCN). Contracted resources similarly have required Commission approval, either case-by-case, or through the Qualifying Facilities (QF) program. Restructuring may change or eliminate these regulatory mechanisms, but operations and planning will continue to have a major impact on system reliability.

AB 1890 assigns responsibility for the reliability of the transmission system to the ISO, but requires various degrees of this Commission's oversight. PU Code Sections 345 and 346 require the ISO to meet reliability criteria no less stringent than those adopted by the Western Systems Coordinating Council (WSCC) and, in its application to the FERC, to seek the authority to acquire the necessary generating and transmission resources. The Commission is directed by PU Code Sections 360, 362, and 363 to review the ISO's FERC application and generating arrangements to assure that the ISO meets reliability criteria. PU Code Section 348 requires the ISO to issue inspection and maintenance standards for transmission by March 31, 1997, while PU Code Section 349 requires the ISO to investigate major system outages. Under PU Code Section 350, the ISO, within six months of its approval by the FERC, in consultation with this Commission and other agencies, must report on reliability in the Western region. Meanwhile, we are directed to adopt standards by March 31, 1997, to assure maintenance of utility distribution systems; as noted above, standards have been proposed in an ongoing proceeding.

During the transition to the new electricity market, we are committed to ensuring that the existing utilities do not reduce maintenance and other efforts. We have already addressed this issue by issuing performance and inspection standards, and will follow up by monitoring utility compliance with those standards. The second and longer-range challenge is to assure reliability in the new structure, where several different entities will share responsibility. The Commission's President and staff members have worked with the Committee for Regional Electric Power Cooperation to set up a working group on regional reliability issues, focusing on setting up enforceable standards throughout the west. Reliability standards are an area where both state and federal cooperation is mandated. This Commission will work closely with the FERC and the parties to ensure that all reliability issues are adequately addressed and that reliability of the electrical system is maintained.

VI. QF Issues

In the original Roadmap Decision, we included QF buyout incentives as an issue to be addressed in the transition cost proceeding. At the May 31, 1996, scoping workshop in that proceeding, parties recommended that consideration of this incentive should be moved to a separate forum, potentially an extension of informal groups addressing QF contract restructuring and short-run avoided cost (SRAC) reform issues. The June 28 ACR indicated that more guidance on these issues would be forthcoming. AB 1890 adds Section 390 to the PU Code, and we are now in the process of implementing the interim SRAC pricing methodology established by that section. Long-term QF pricing was also addressed in PU Code Section 390, but implementation issues and contract restructuring issues require further consideration.

VI.A. Long-Term Pricing

PU Code Section 390 provides for SRAC energy payments to be based on the PX clearing price if we have made a finding that the PX is functioning properly for these purposes, and either 1) the fossil-fuel generation units are authorized to charge market-based prices and the "going forward" costs of these units are recovered from the PX or the ISO, or 2) the costs are based on operating costs for particular units when reactive power/voltage support is not yet procurable at market-based prices at locations where it is needed, or 3) the utility has divested 90% of its gas-fired generation facilities that were operated to meet load in 1994 and 1995. Recognizing that the information by which to make the necessary findings pursuant to PU Code Section 390 will not be available for at least another year, we will establish a procedure to implement these provisions as we more closely approach the 1998 transition period.

VI.B. QF Contract Restructuring

In our Preferred Policy Decision, we proposed an incentive mechanism to encourage the restructuring of QF contracts so that total transition costs might be reduced. In that decision, we endorsed an approach that would involve both monetary incentives to shareholders and conditions which foster voluntary, nondiscriminatory negotiations. This approach would allow shareholders to retain 10% of the net ratepayer benefits resulting from a renegotiation, which would be reflected by an adjustment to the transition cost total. Modification of QF contracts should follow our existing principles that the modifications are voluntary on the part of the QF and should provide ratepayer benefits. We indicated an interest in the recommendations of relevant stakeholders.

PU Code Section 367 provides for the recovery of transition costs stemming from power purchase contracts, including approved renegotiations and buyouts, as long as those contract costs were reflected in rates as of December 20, 1995. We are interested in establishing a generic and possibly expedited process by which we can assess the reasonableness of contract restructuring in a manner which respects the principles outlined in our Preferred Policy Decision. Accordingly, we seek proposals from the respondents and interested parties to this proceeding which would establish a generic method to review contract modifications, possibly including standard measures of reasonableness. We encourage parties to prepare joint proposals. Such proposals must be filed and served on the master service list in the electric restructuring docket by February 10, 1997. We will then provide additional procedural guidance, including establishing a schedule for commenting on these proposals.

VII. CEQA

We have terminated the preparation of a policy-level Environmental Impact Report (EIR) pursuant to CEQA in light of AB 1890, as discussed in a separate decision addressing CEQA issues.

The next steps for our compliance with CEQA are unchanged, and are fully articulated in Rule 17.1 of our Rules of Practice and Procedure. Rule 17.1 applies when Commission approval is required by law, except for projects for which an application must be filed with the CEC, pursuant to Public Resources Code Section 25500. For example, Rule 17.1(d) states that applications for Commission approval must include a Proponent's Environmental Assessment (PEA) in one of two forms. Recent examples of this requirement are PG&E's A.96-11-020 and Edison's A.96-11-046 requesting our approval to sell specified generating plants and related assets.

Additionally, as we go forward in implementing the transition to competition, we would encourage working groups to consider CEQA issues as they develop recommendations; at the time working group recommendations are made, any party may file a Motion for Determination of Applicability of CEQA pursuant to Rule 17.2.

Findings of Fact

In conformance with the requirements of AB 1890 and the Preferred Policy Decision, the necessary components of a restructured electric services industry must be in place prior to the actual implementation date, in order to allow the transition period to begin no later than January 1, 1998.

The schedules provided in this updated Roadmap Decision may change somewhat, but represent the necessary goals for achieving the beginning of the transition period for electric restructuring, no later than January 1, 1998.

We will carefully scrutinize PG&E's, Edison's, and SDG&E's Phase II ISO filings at FERC to ensure the independence of the ISO and to ensure that vertical market power issues are adequately addressed.

Effective mitigation measures should be in place no later than January 1, 1998, in order to mitigate the potential exercise of market power.

Market power issues addressed at the FERC will overlap with other state proceedings, such as the generation PBR proceedings (A.96-07-009 et al.), the transition ccst recovery proceedings (A.96-08-001 et al.), and the direct access proceeding in this docket.

At a minimum, 50% voluntary divestiture of PG&E's and Edison's fossil fueled generation assets is adequate as a starting point in examining the market power issues relating to divestiture.

It is reasonable at this time to retain the voluntary divestiture incentive of 10 basis points for every 10% divested, but this issue may be addressed further in divestiture proceedings.

AB 1890 reaffirms our view that meaningful competition will result from direct access and that direct access should commence by January 1, 1998.

The provisions of AB 1890 affect the time-frame of the default phase-in schedule established in the Preferred Policy Decision.

The default phase-in schedule may no longer be necessary, because PG&E, Edison, and SDG&E are recommending a different approach.

AB 1890 mandates a registration program for energy service providers.

AB 1890 requires the registration of entities which were not considered in the Preferred Policy Decision, i.e., sellers of electricity services, and aggregators who are public agencies, cities, counties, or special districts that offer electrical services to residential and small customers within the service territory of an electric corporation.

Consumer protection and education measures, including measures related to low-income consumer education and protection, must be in place well before the transition period begins.

Direct access tariffs must be approved by October 1997 in order to provide sufficient time for market participants and customers to consider their choices in electric services.

Our decision on funding levels for public purpose programs must be incorporated into the decision making process in the ratesetting/unbundling proceeding, in order for public purpose program costs to be identified on customer bills.

Some form of review and verification will still be necessary after the new market structure is in place to verify the accuracy and fairness of the utilities' recovery of PX costs.

The RAP will consolidate all pending revenue changes, and track utility revenues at present rate levels for the purpose of comparison with authorized amounts.

Under the rate freeze, the sum of all rate components such as generation, transmission, distribution, CTC, and public purpose charges, cannot exceed the frozen rate level.

Policy issues related to metering and billing should be addressed in a separate track from the unbundling and direct access issue areas.

Under AB 1890, recovery of nuclear investments and the ICIP prices are limited to the period of the rate freeze or until the authorized transition costs are fully recovered.

Pursuant to AB 1890, the calculation and collection of most transition costs must be completed by March 31, 2002. Exceptions include, for example, transition costs arising from SONGS, which shall be collected until 2004; costs arising from transition obligations to utility employees, which may be collected through 2006; and costs associated with purchased power contracts, which will, for the most part, be collected for the duration of the contract or until the contract is restructured.

Additional steps will be necessary to establish the specific methodology to record transition costs arising from assets as they are divested or market valued through appraisal, and also to establish details associated with the appraisal market valuation methodology. However, these issues are not critical to implementation of direct access in 1998, and may therefore be placed in a later phase of the transition cost proceedings.

It is crucial that California's utility customers are assured of a high degree of reliability in their electric service during and after the transition to a more competitive electricity market.

We have terminated the preparation of a policy-level EIR pursuant to CEQA in light of AB 1890, pursuant to our order on CEQA issues.

Conclusions of Law

The mandatory buy-sell requirement is not inconsistent with AB 1890, but the operable period should end on December 31, 2001, because of the time period for recovery of the majority of transition costs.

AB 1890 does not affect our authority to address competition and market power problems in the manner set forth in the Preferred Policy Decision, including the proposal of voluntary divestiture as a means for mitigating such problems.

In AB 1890, the Legislature reaffirmed our role in addressing issues concerning competition, market power and divestiture.

We are under a duty to consider and resolve, in the public interest, issues concerning competition, which include market power problems, which is part of our responsibilities for making sure that the rates for ratepayers and the practices and methods of generation, distribution, transmission, storage, and supply utilized by the utility are just and reasonable.

Fulfillment of this duty in no way interferes with the jurisdiction of the FERC.

AB 1890 mandates a registration requirement for energy service providers offering electrical service to residential and small commercial customers within the service territory of a electric corporation, but limits the requirement for the registration of brokers.

Because reasonableness reviews are the quid pro quo of balancing account treatment, these reviews should continue for the interim period, at least until the utilities' fuel procurement practices are no longer undertaken in a regulated regime.

In order to ensure that our regulatory goal of establishing fair and reasonable rates for the regulated portion of utility operations and services is achieved, it is reasonable to establish a new proceeding to consider ratemaking issues related to each electric utility's revenues.

PG&E, Edison, and SDG&E must continue to comply with the guidelines and reporting requirements established in D.95-07-055.

AB 1890 confirms the rate of return on equity we adopted in the Preferred Policy Decision; therefore, it is appropriate to use 90% of the embedded cost of debt as a reasonable rate of return on equity for generation facilities.

AB 1890 emphasizes the need for reliability in the electric system through provisions affecting the ISO as well as this Commission.

AB 1890 declares a state policy that California enter an interstate compact with other western states to allow enforcement of reliability standards on the region's utilities.

AB 1890 assigns responsibility for the reliability of the transmission system to the ISO, but requires various degrees of Commission oversight and coordination.

Establishing and reviewing reliability standards is an important area where state and federal cooperation is mandated.

Modification of QF contracts should follow our existing principles that the modifications are voluntary on the part of the QF and should provide ratepayer benefits.

It is reasonable to establish a generic process by which we can assess QF contract renegotiation issues consistent with AB 1890 and our Preferred Policy Decision.

Specific Commission actions during the transition to competition may have CEQA implications, which must be considered.

To ensure that proceedings related to electric restructuring are coordinated in an expeditious manner, this order should be effective today.

INTERIM ORDER

IT IS ORDERED that:

Beginning in 1998, the Revenue Adjustment Proceeding (RAP) shall be established as a new annual proceeding to review, track, and compare each utility's authorized revenue requirements with the actual recorded revenues and to make any necessary adjustments or updates due to the authorized revenues for performance-based ratemaking, various power purchase contracts, public purpose programs, nuclear facilities, nuclear decommissioning, transition costs and other proceedings.

In the absence of general rate cases, the Nuclear Decommissioning Costs Triennial Proceeding (NDCTP) shall be established to determine the decommissioning costs and establish the annual revenue requirement and attrition factors over a three-year period. Once the annual revenue requirement is established in the NDCTP, the nuclear decommissioning charge shall be established in the unbundling and ratesetting issue areas.

The respondents to this proceeding shall and interested parties may file and serve proposals to establish a generic method to review contract modifications, possibly including standard measures of reasonableness. Parties may prepare joint proposals. Such proposals shall be filed and served on the master service list in the electric restructuring docket and are due on February 10, 1997.

Specific utility applications and working group reports which require Commission approval shall explicitly comply with the requirements of Rule 17.1, as applicable.

The assigned Commissioners or Administrative Law Judges, acting on their behalf, may coordinate the Commission's efforts by amending the schedules,

modifying the Working Groups, or issuing rulings that will facilitate the goals set forth in this decision.

This order is effective today.

Dated December 20, 1996, at San Francisco, California.

P. GREGORY CONLON

President

DANIEL Wm. FESSLER

JESSIE J. KNIGHT, JR.

HENRY M. DUQUE

JOSIAH L. NEEPER

Commissioners

TABLE OF CONTENTS

INTERIM OPINION 2

I. Introduction 2

II. Market Structure Issues 3

II.A. FERC Issues 4

II.A.1. Petition for Declaratory Order (FERC Docket No. EL96-48-000) 4

II.A.2. Application to Convey Operational Control of Designated Jurisdictional Facilities To An Independent System Operator (FERC Docket No. EC96-19-000). 5

II.A.3. Joint Application for Authority to Sell Electric Energy at Market-Based Rates Using a Power Exchange (FERC Docket No. ER96-1663-000.) 6

II.B. Mandatory Buy-Sell 7

II.C. Market Power 9

II.D. Voluntary Divestiture 11

II.D.1. 50 Percent Voluntary Divestiture 12

II.D.2. Incentive for Voluntary Divestiture 15

III. Consumer Choice Issues: Direct Access, Consumer Protection and Education, and Public Purpose Programs 16

III.A. Eligibility for Direct Access 16

III.B. Registration 17

III.C. Direct Access and Consumer Protection and Education Procedural Issues 18

III.D. Public Purpose Programs 21

IV. Ratesetting Issues 22

IV.A. Unbundling Issues 24

IV.A.1. Coordination with other proceedings 25

IV.B. Unbundling Utility Revenue Cycle Services 26

IV.C. Performance-Based Ratemaking 28

IV.1. Ongoing Performance-Based Ratemaking Mechanisms 28

IV.C.2. Generation PBRs 28

IV.C.3. Distribution PBRs 28

IV.C.4. Ratemaking Treatment for Nuclear Generating Assets 29

IV.D. Transition Costs 31

IV.D.1. 90% Return on Equity 31

IV.D.2. Transition Cost Procedural Issues 33

IV.E. Rate Reduction Bonds 35

V. Reliability 36

VI. QF Issues 38

VI.A. Long-Term Pricing 38

VI.B. QF Contract Restructuring 39

VII. CEQA 39

Findings of Fact 40

Conclusions of Law 42

INTERIM ORDER 44

APPENDIX

Footnote continued on next page.

(1) D.95-12-063, as modified by D.96-01-009.

(2) In this filing, this Commission also informed the FERC that it would file additional comments with respect to market power analyses in October, 1996. Comments on market power were filed with the FERC on October 17.

(3) These horizontal market power studies were filed in FERC Docket No. ER96-1663-000, in support of the Applicants' request for market-based rates for the PX. These studies have been submitted to this Commission, and are part of the record in our electric restructuring proceeding.

(4) PG&E proposes to divest 3,074 megawatts (MW) of generating capacity—half its fossil-fired generation. (A.96-11-020, p. 5.)

(5) Edison proposes to divest 9,952 dependable MW of summer generating capacity—100% of its California fossil-fired generating capacity, except for its Pebbly Beach generation facility. (A.96-11-046, p. 2.)

(6) To the extent that FERC is a decision maker on these actions, these dates represent our best estimate at this time.

(7) Even without the enactment of AB 1890, we are under a duty to consider and resolve, in the public interest, issues concerning competition, which would include market power problems. (See Northern California Power Agency v. Public Util. Com. (1971) 5 Cal.3d 370, 377-379.)

(8) In its Comments, CLECA focuses on local market power problems, and raises issues which we do not address in today's order. With regard to the 50% voluntary divestiture proposal, CLECA suggests that "the precise percentage figure is likely to be less important than the resolution of the problems created by the 'must run' units." (CLECA's Comments to the CCR, p. 2.)

(9) We refute the criticism that we are resolving the market power problems with a single decision. (CEERT Comments to the CCR, p. 5.)

(10) Also, AB 1890 includes an additional requirement relating to eligibility for direct access not contemplated in the Policy Decision's default schedule. PU Code Section 365(b)(2) provides that "[c]ustomers shall be eligible for direct access irrespective of any direct access phase-in implemented pursuant to this section if at least one-half of that customer's electrical load is supplied by energy from a renewable resource provider certified pursuant to Section 383. . . ." This new statutory requirement will need to be factored into any phase-in program that we might adopt.

(11) It is noted that for purposes of AB 1890, except for an electrical corporation as defined in PU Code Section 218, energy service providers, including aggregators, brokers and marketers, are not public utilities simply because of "ownership, control, operation, or management of an electric plant used for direct transactions or participation directly or indirectly in direct transactions. . . ." (PU Code § 216(i).)

(12) These choices include: direct access; real-time pricing and time-of-use rate options; and contracts-for-differences.

(13) These reports were filed pursuant to D.96-03-022 and a Joint Assigned Commissioner Ruling issued May 17, 1996.

(14) The Preferred Policy Decision, in Ordering Paragraph 40, directed the establishment of an independent education trust. The September 30, 1996, DAWG report refers to this trust as the Restructured Electric Service Education Trust (RESET). AB 1890 requires the utilities to design and implement a customer education program, in conjunction with the Commission, and subject to our approval.

(15) On November 7, SDG&E requested an extension from November 15 until December 6 to file its rate and product unbundling application. This request was granted and extended to PG&E and Edison in an Assigned Commissioner's Ruling dated November 8, 1996.

(16) See discussion on rate reduction bonds below.

(17) As discussed in the Unbundling Report filed by the Ratesetting Working Group on August 26, SDG&E uses the term revenue cycle services, which include metering, billing, customer services, and uncollectibles.

(18) The issues raised in D.96-10-074, Ordering Paragraph 3 will be addressed in this separate track.

(19) For example, SDG&E's Base Rate mechanism adopted in D.94-08-023 has been in place since 1994. This mechanism is scheduled for a midterm review in 1997. A workshop was held on December 4, with a prehearing conference on December 11, 1996 to establish future schedules.