As a threshold matter, we reject the proposed Joint Recommendation on both substantive and procedural grounds. We discuss the procedural concerns first.
We are very concerned regarding the allegations of TURN et al. and ORA that they were systematically excluded from negotiations and discussions. Although this proposal is not presented as a settlement and is not being reviewed as a settlement, excluding active parties from discussions about proposal which are eventually brought before this Commission only weakens the recommendation, particularly when such proposals are submitted only days before reply briefs are due. Not only does this exclusion impact the ability of objecting parties to respond appropriately in briefs, it has the potential effect of impacting the entire time line of this proceeding. Certainly, the moving parties’ recommendation would have carried more weight had the representatives of small consumers been included in these discussions.
Rule 51(d) states that "’stipulation’ means an agreement between some or all of the parties to a Commission proceeding on the resolution of any issue of law or fact material to the proceeding." Edison states specifically that the Joint Recommendation does not fit this definition, but instead "represents the consensus of its signatories to modify their positions in this proceeding and jointly recommend that consensus to the Commission. Because the issue arose from differing interpretations of the complex interplay of statutory provisions in AB 1890, it took approximately six weeks of discussions to arrive at this consensus." (Edison’s Supplemental Brief, p. 9.) We agree that the parties to the Joint Recommendation appear to have reversed their positions on several issues. Such agreements coming in so late in this phase are problematic for two reasons. While the Commission wishes to encourage informal negotiations and consensus among the parties, it is difficult to evaluate why such a change in position has ensued. If such agreements were submitted well before opening briefs, those briefs could have provided more explanation and rationale. Secondly, as we move forward in implementing electric restructuring, the schedules for hearings in many issue areas will necessarily be compressed. We reject this fact as a reason to exclude active parties from discussions intended to arrive at consensus agreements. Certainly, if this joint recommendation had been presented as a settlement (and not necessarily an all-party settlement), it would have carried more weight. [ As we found in D.96-01-011, if settling parties choose not to accommodate all affected interest groups, an all-party settlement cannot be achieved and our standard of review is heightened. (D.96-01-011, mimeo. at pp. 24, 266.)] We therefore accord the Joint Recommendation appropriate weight, as it is not a settlement, and appears to be merely a consolidation of certain interpretations of AB 1890. As we move forward to implement AB 1890, statutory interpretation is not a duty that we can relinquish to the parties, as we discuss below.
Furthermore, the Joint Recommendation proposes consensus treatment of issues that are beyond the scope of this proceeding. This document was filed in the above-captioned transition cost proceedings, not in the electric restructuring rulemaking. Therefore, even assuming for argument’s sake that we were persuaded by the Joint Recommendation, we would be unable without further process to address elements of the Joint Recommendation that are outside the scope of the transition cost proceeding. For example, parties in R.94-04-031/I.94-04-032 have not had the opportunity to respond to or assess the reasonableness of CUE’s position at FERC or its position regarding the divestiture applications.
In addition, as ORA discusses in its supplemental brief, the acceleration of QF renegotiations is being addressed in R.94-04-031/ I.94-04-032, in which we are reviewing various proposals for streamlining the restructuring and approval process for QF contracts. We decline to review portions of the Joint Recommendation that address these issues on a piecemeal basis.
While we are interested in the proponents’ interpretation of the statutory language, it is this Commission’s duty to implement the statute according to the plain meaning of the statute and to look to the legislative history where there is ambiguity, according to established rules of statutory construction. These rules do not include necessarily accepting the interpretations of the parties, despite the fact that certain parties were active in the AB 1890 discussions. As we recently stated in D.97-02-014:
"When construing the purpose and intent of a statute, the California Supreme Court has clearly stated that it is of little assistance to consider the motives or understandings of single individuals, because such views may not reflect the views of other Legislators who voted for the bill. (Freedom Newspapers, Inc. v. Orange County Employees Retirement System Board (1993) 6 Cal. 4th 821, 831.) This admonition is particularly apt in this instance, where lobbyists and private proponents of legislation are relying upon their own views and intentions in arguing for a particular interpretation of AB 1890." (D.97-02-014, mimeo. at 49.)
The only way in which we could find the Joint Recommendation persuasive is if the Commission’s own independent review of the statute leads to the same conclusion as to what the Legislature intended, as TURN et al. point out. (Supplementary Brief of TURN et al., p. 3.) Again, we turn to our previous findings in D.97-02-014:
"To determine that intent, we first turn to the language of the statute. (Delaney v. Superior Court (1990) 50 Cal. 3d 785, 798.) The United States Supreme Court stated this principle as follows:
"’[I]n interpreting a statute, [one] should always turn to one cardinal rule before all others. We have stated time and again that [one] must presume that the legislation says in statute what it means and means in statute what it says there.’ (Connecticut National Bank v. German (1992) 503 U.S. 249, 253-254; 112A S.Ct. 1146, 1149.)
"The California Supreme Court explains this fundamental principle more expansively:
"‘Pursuant to established principles, our first task in construing a statute is to ascertain the intent of the Legislature so as to effectuate the purposes of the law. In determining such intent, a court must look first to the words of the statute themselves, giving to the language its usual, ordinary import and according significance, if possible, to every word, phrase and sentence in pursuance of the legislative purpose. A construction making some words surplusage is to be avoided.’ (Dyna-med, Inc. v. Fair Employment and Housing Commission (1987) 43 Cal. 3d 1379, 1386-1387, 241 Cal. Rptr. 67, 70.)" (D.97-02-014, mimeo. at 41.)
We must use these clearly-stated guidelines to implement the newly-added Public Utilities Code sections relating to transition cost recovery. Because there is no specific reference to accounting methodology in the statute, we must apply our knowledge of current ratemaking practices, common sense and our duty in carrying out the public interest in looking to the words of the statute, giving each word its usual, ordinary import.
First, while AB 1890 provides the utilities with a fair opportunity to fully recover transition costs, we do not find that AB 1890 ensures that transition cost recovery is without risk. Therefore, we reject the proposition that write-offs must be avoided at all costs. Again, we look to the unambiguous wording of the statute.
Section 1(b) of AB 1890 reads as follows:
"(b)… It is the…intent of the Legislature that during a limited transition period ending March 31, 2002, to provide for all of the following:
"(1) Accelerated, equitable, nonbypassable recovery of transition costs associated with uneconomic utility investments and contractual obligations.
"(5) a fire wall that protects residential and small business consumers from paying for statewide transition cost policy exemptions required for reasons of equity or business development and retention.
"(6) Protection of the interests of utility employees who might otherwise be economically displaced in a restructured industry."
Section 330 states, in relevant part:
"(s) It is proper to allow electrical corporations an opportunity to continue to recover, over a reasonable transition period, those costs and categories of costs for generation-related assets and obligations, including costs associated with any subsequent renegotiation or buyout of existing generation-related contracts, that the commission, prior to December 20, 1995, had authorized for collection in rates and that may not be recoverable in market prices in a competitive generation market, and appropriate additions incurred after December 20, 1995 for capital additions to generating facilities existing as of December 20, 1995 that the commission determines are reasonable and should be recovered, provided that the costs are necessary to maintain those facilities through December 31, 2001. In determining the costs to be recovered, it is appropriate to net the negative value of above market assets against the positive value of below market assets.
"(t) The transition to a competitive generation market should be orderly, protect electric system reliability, provide the investors in these electrical corporations with a fair opportunity to fully recover the costs associated with commission approved generation-related assets and obligations and be completed as expeditiously as possible.
"(u) The transition to expanded customer choice, competitive markets, and performance based ratemaking …can produce hardships for employees who have dedicated their working lives to utility employment. It is preferable that any necessary reductions in the utility work force directly caused by electrical restructuring, be accomplished through offers of voluntary severance, retraining, early retirement, outplacement, and related benefits. Whether work force reductions are voluntary or involuntary, reasonable costs associated with these sorts of benefits should be included in the competition transition charge."
Finally, Section 368(a) provides, as follows:
"The cost recovery plan shall set rates for each customer class, rate schedule, contract, or tariff option, at levels equal to the level as shown on electric rate schedules as of June 10, 1996, provided that rates for residential and small commercial customers shall be reduced so that these customers shall receive rate reductions of no less than 10 percent for 1998 continuing through 2002. These rate levels for each customer class, rate schedule, contract, or tariff option shall remain in effect until the earlier of March 31, 2002, or the date on which the commission-authorized costs for utility generation-related assets and obligations have been fully recovered. The electrical corporation shall be at risk for those costs not recovered during that time period. Each utility shall amortize its total uneconomic costs, to the extent possible, such that each year during the transition period its recorded rate of return on the remaining uneconomic assets does not exceed its authorized rate of return for those assets. For purposes of determining the extent to which the costs have been recovered, any over-collections recorded in the Energy Costs Adjustment Clause and Electric Revenue Adjustment Mechanism balancing accounts, as of December 31, 1996, shall be credited to the recovery of the costs." (Emphasis added.)
The only language in AB 1890 that speaks to possible deferral of current costs is addressed in Section 376, which states:
"To the extent that the costs of programs to accommodate the implementation of direct access, the Power Exchange, and the Independent System Operator, that have been funded by an electrical corporation and have been found by the commission or the Federal Energy Regulatory Commission to be recoverable from the utility’s customers, reduce an electrical corporation’s opportunity to recover its utility generation-related plant and regulatory assets by the end of the year 2001, the electrical corporation may recover unrecovered utility generation-related plant and regulatory assets after December 31, 2001, in an amount equal to the utility’s cost of commission-approved or Federal Energy Regulatory Commission approved restructuring-related implementation programs…." (Emphasis added.)
No other clause in any other sections relating to transition costs specify this sort of recovery. Therefore, it is clear that these § 376 costs can be deferred.
It is particularly important to read § 381(d) in the context of both § 381 and the entire statute as a whole. PG&E, Edison, and SDG&E assert that to the extent that generation-related transition cost recovery is impacted by the recovery of renewable program costs, this "displaced" transition cost recovery may be deferred and recovered in the three-month period which extends the rate freeze, beginning on January 1, 2002.
Section 381 addresses both the funding of various public purpose programs and the collection and recovery of those funds. One purpose of § 381(d) is to allow no more than $75 million to be collected through the CTC so as to allow the funding level for renewable programs to equal $540 million, as we have stated in D.97-02-014, Ordering Paragraph 2(d):
". . . Pursuant to PU Code § 381(d), an additional $75 million shall be collected by a three-month extension of the competition transition charge beyond its otherwise applicable termination of December 31, 2001. These funds shall be transferred to the CEC pursuant to § 383(a)."
(D.92-02-014, mimeo. at p. 92.)
We agree with the utilities that, other than this additional $75 million which is to be collected through the CTC during the extended 3-month period of the rate freeze for purposes of funding the renewables programs, other costs of funding these programs and other public purpose programs as addressed in § 381 and D.97-02-014 are collected through a separate nonbypassable charge. We also agree that the costs of funding the renewable programs cannot be deferred. While the issue of deferral of generation-related transition costs and "displaced" recovery is not addressed in either §§ 381(d), 367, or 368, we must consider the interrelationship of the rate freeze, the collection of funding for the renewable program costs, and headroom.
As previously discussed, rates are frozen at the June 10, 1996 levels. Funding for the renewable program costs addressed in § 381(b)(3) is not provided for within these rate levels. Because the statute allows the utilities a fair opportunity to fully recover transition costs, as discussed above, it is reasonable that to the extent the funding of these programs jeopardizes the recovery of generation-related transition costs by December 31, 2001, (i.e., reduces headroom), those displaced costs may be recovered during the three-month extended period for CTC collection. However, this deferral should only occur to the extent necessary; i.e., the utilities should make every effort to recover all generation-related transition costs before December 31, 2001. In addition, any carrying costs associated with funding the renewable program costs must be borne by the shareholders and will not be collected as transition costs.
In addition to authorizing the $75 million to be allocated to funding renewables programs, § 381 allows the 3-month extension of the rate freeze to continue to collect certain other costs. These funds are then to be reallocated for purposes of funding renewable programs, to the extent additional moneys remain after funding costs associated with § 374 (outstanding issues related to implementation of irrigation
district exemptions) and issues related to Edison’s contract arrangements in the BRPU settlements, as described in § 381(c) (4) and § 381( c)(5), as follows:
"(4) Up to fifty million dollars ($50,000,000) of the amount collected pursuant to subdivision (d) may be used to resolve outstanding issues related to implementation of subdivision (a) of Section 374. Moneys remaining after fully funding the provisions of this paragraph shall be reallocated for purposes of paragraph (3).
"(5) Up to ninety million ($90,000,000) of the amount collected pursuant to subdivision (d) may be used to resolve outstanding issues related to contractual arrangements in the Southern California Edison service territory stemming from the Biennial Resource Planning Update auction. Moneys remaining after fully funding the provisions of this paragraph shall be reallocated for purposes of paragraph (3)."
Therefore, we find that deferral of recovery of generation-related transition costs to the three-month period, beginning January 1, 2002 and ending March 31, 2002, is permitted by § 381(d). The CTC is extended for three months beyond its otherwise applicable termination date to accomplish the following collection purposes: 1) $75 million is to be collected in the CTC in the three-month period beginning January 1, 2002 and allocated to the funding of renewable programs; 2) up to $50 million may be collected in the CTC in this three-month period for purposes of funding outstanding issues related to implementation of § 374; any remaining funds of this amount are allocated to renewables; 3) up to $90 million may be collected in the CTC in this three-month period for purposes of funding outstanding issues related to Edison’s BRPU settlements; any remaining funds of this amount are allocated to renewables. Any other funds collected during the three-month period shall be applied to the deferred generation-related transition costs. This approach both ensures that the aggregate portion of the funds allocated to renewable resources equals $540 million and ensures that the costs of these programs are collected, as is required by the statute.
It is in the interests of both ratepayers and shareholders that the greatest amount of revenues be available to collect transition costs. Ratepayers benefit because if transition costs are collected as expeditiously as possible, the rate freeze may end before the end of the mandated transition period. Shareholders benefit because if the utilities maximize the amount of available dollars to recover actual transition costs, rather than interest and carrying costs, there is a greater chance of full recovery of those costs. Even PG&E agrees that "because it is uncertain how much headroom will be available and whether utilities would be able to recover all of their at risk transition costs during the rate freeze, the utilities will of necessity accelerate costs in a manner that maximizes recovery and minimizes the risk of write-offs." (PG&E’s Reply Brief, p. 5). PG&E also agrees with TURN et al. ’s conclusion that the accelerated recovery of transition costs of assets bearing higher rates of return "would benefit shareholders as well [as ratepayers], because if more of the CTC revenue is applied against stranded costs themselves rather than towards interest there is less of an opportunity that utilities will forgo recovery of some stranded costs and hence less likelihood of an adverse reaction by financial markets." (PG&E’s Reply Brief, p. 7, quoting TURN et al.’s Opening Brief.) PG&E has stated that "TURN correctly recognizes that IOU and ratepayer interests are aligned; ratepayers want the freeze to end as soon as possible and IOUs want to recover all of their at risk costs as soon as possible." (PG&E’s Reply Brief, p. 5.) In its original proposal in this proceeding, Edison recommends accelerated recovery of transition costs for only those assets earning a rate of return.
Accelerating cost recovery for the assets earning a rate of return will allow ratepayers to benefit in another way. As FEA points out, the utilities are proposing to apply a relatively low interest rate (the 90-day commercial paper rate) to the revenue account, to the extent that the utilities choose to leave a balance remaining in these accounts. At the same time, the utilities would be earning a somewhat higher rate of return on generation assets on which they similarly chose not to accelerate depreciation. Therefore, if utilities are allowed to accelerate recovery of costs of assets that do not bear a rate of return before those that do, the utilities will earn the higher rate of return, while the ratepayers earn only the commercial paper interest rate on the revenue account. This is an inequity that is counter to the intent of the statute and must be avoided.
Generally, parties have agreed that, except for employee-related transition costs and restructuring implementation costs, current costs should be recovered first. PG&E defines current costs as those costs which are being recovered in today’s rates, including depreciation on a regular schedule. (TR: 208-209.) In its original proposal, Edison defines current costs to include accelerated depreciation on a 48-month amortization schedule, including associated taxes and a reduced rate of return. PG&E argues that it needs flexibility to determine which assets should be depreciated more quickly, and that this acceleration cannot be done on a predetermined basis. PG&E asserts that assets should be depreciated to market value, but not below. PG&E recommends that recovery of regulatory assets should be accelerated first (that is, the difference between what is scheduled to be included in current rates and the total amount of regulatory assets at risk). Therefore, PG&E would not accelerate cost recovery of any of the depreciable assets so long as it believed that the regulatory assets were at risk. Edison does not take a position on regulatory assets, other than stating that there should not be too great a disparity between Category I cost recovery and Category II cost recovery, which might otherwise trigger write-offs under FASB Statement No. 71.
In the Preferred Policy Decision, we defined regulatory obligations as:
"the transition costs that . . . are related to various deferred costs and outstanding balancing accounts balances that the utility has accrued under cost of service regulation. In most cases, we have already approved recovery of these costs, and they are reflected in outstanding balances of balancing accounts. Examples of these types of costs include deferred operating expenses, deferred taxes, unamortized loss from sale of assets, unamortized debt expense, costs associated with issuing or reacquiring debt, and nuclear decommissioning expenses.
"We plan to evaluate specific account balances and determine the amounts that will be included as part of transition costs during the implementation phase of this rulemaking, but these amounts should relate only to generation assets affected by this restructuring." (Preferred Policy Decision, mimeo. at pp. 133-134.)
It is premature to conclude that write-offs of regulatory assets will be required for financial accounting purposes. Various definitions of regulatory obligations have been presented by the utilities and parties in Phase 1A of this proceeding. We have not yet adopted a definition of regulatory assets for purposes of transition cost recovery, but will determine the applicable definition to be used in defining regulatory assets in Phase 2 of this proceeding. We note that at least two decisions have been issued after the Preferred Policy Decision and shortly before AB 1890 was signed into law that create additional "regulatory assets." [ D.96-09-037 was issued on September 4, 1996, shortly before AB 1890 was signed into law. In that decision, we adopted a settlement which provided, among other things, that the weighted-average rate base of prior years’ revenue requirement to be placed in PG&E’s rate base as a regulatory asset will be for $14.40 million for 1995. D.96-06-061 was issued on June 19, 1996. Again, this decision created a regulatory asset. "The loss on depreciable property will be recovered from ratepayers, although not through rate base, but rather through creation of a ‘regulatory asset.’ . . . This credit will be offset by the new $1,577,000 ‘regulatory asset’ which will be amortized over a 5-year period (1996 through 2000). (fn: Base revenues in the period from 1977 through 2000 will include an annual $376,000 allotted to assure that the regulatory asset set up can be fully amortized." (D.96-06-061, mimeo. at 10.)] It is not clear at this point whether regulatory assets are properly categorized. In fact, in D.88-12-094, we found that we were not prepared to adopt FASB Statement No. 71 for ratemaking purposes. (30 CPUC 2d 506, 520.). [ We do not necessarily require that the utilities we regulate adhere to particular FASB statements for ratemaking purposes. In D.88-03-072, the Commission declined to endorse FASB Statement No. 87, finding that considerations other than consistency with GAAP should be considered and that GAAP should not be determinative for ratemaking purposes. (27 CPUC 2d 550, 552.)]
We note that in D.92-12-015, we accepted the following definition in terms of PBOP and the applicability of FASB Statement No. 106:
"A regulatory asset is the recording of the utilities’ costs not currently recoverable for ratemaking purpose[s]. To qualify as a regulatory asset, it must be probable that future revenue in the amount at least equal to the asset will result from inclusion of that cost in allowable costs for ratemaking purposes and must be based on available evidence that future revenue will be provided to permit recovery of the previously incurred cost rather than to provide for expected levels of similar future costs." (46 CPUC 2d 499, 536.)
Pursuant to § 367, the Commission must make final determinations of the uneconomic costs associated with generation-related regulatory assets and obligations.
The FASB is an authoritative body which establishes a common set of accounting concepts, standards, procedures, and conventions, which are widely known as "Generally Accepted Accounting Principles" or "GAAP" and are used by most enterprises to prepare external financial statements. We note that FASB Statement No. 71 has been modified by FASB Statement No. 90, FASB Statement No. 92, and most recently by FASB Statement No. 121, which amends FASB Statement No. 71, paragraphs 9 and 10, which define probability of recovery. FASB Statement No. 121 states that:
"The term probable is used in this Statement consistent with its use in FASB Statement 5, Accounting for Contingencies. Statement 5 defines probable as an area within a range of the likelihood that a future event or events will occur. That range is from probable to remote as follows:
Probable. The future event or events are likely to occur.
Reasonably possible. The chance of the future event or events occurring is more than remote but less than likely.
Remote. The chance of the future event or events occurring is slight." (FASB Original Pronouncements, Accounting Standards as of June 1, 1995, Volume 1 FASB Statement of Standards.)
With this context in mind, we find that the recovery of regulatory assets is probable, i.e., likely to occur. During the rate freeze, current ratemaking principles remain essentially intact, and we have reasonable certainty that costs will be covered. Transition cost recovery is now mandated by law and there is no reason to assume that the frozen rates will not result in sufficient headroom to fully recover transition costs. The utilities are already accruing revenues to offset transition costs. For example, the Energy Cost Adjustment Clause (ECAC) and Electric Rate Adjustment Mechanism (ERAM) overcollections for 1996 are already accounted for to offset transition costs, which have the potential to increase the amount of revenues available to provide for transition cost recovery. Moreover, pursuant to D.96-12-077, the rate freeze began this year, which has the effect of allowing the utilities to accrue revenue prior to the beginning of the mandated transition period, thus the recovery period for revenue purposes is five years rather than four. [ As TURN et al. point out, in D.96-11-041, we adopted a proxy estimate of 39% of current rates going towards transition cost recovery. PG&E’s current revenues are approximately $7.5 billion per year (D.95-12-051, Appendix C). Over 5 years, all things being equal, total revenues would equal $37.5 billion; 39% of that figure is approximately $14.6 billion, which exceeds PG&E’s estimates of transition costs, which range from $8.4 billion to $14.1 billion, depending on a market price scenarios ranging from 3.5 cents per kilowatt hour to 1.5 cents per kilowatt hour. (Exhibit 3, p. 7 - 5.)] In D.96-12-080, we recognized that under normal ratemaking practices, PG&E’s electric rates would have been reduced by approximately 10% to account for the $720.4 million decrease in its authorized revenue requirement. (D.96-12-080, mimeo. at 2.)
Furthermore, § 330(w) states that electrical corporations shall, by June 1, 1997, or earlier, apply concurrently for financing orders from this Commission and for rate reduction bonds from the California Infrastructure and Economic Development Bank. While particular issues associated with rate reduction bonds and transition cost recovery have not yet been addressed, we anticipate that this influx of cash from the asset securitization will have a significant impact on transition cost recovery. Therefore, actual transition cost recovery will thus depend on the outcome of several proceedings, the Power Exchange prices during the rate freeze and market valuation. The total amount of stranded costs related to Diablo Canyon will be authorized in a pending decision in A.96-03-054. The eligibility and magnitude of certain costs for transition cost recovery are yet to be determined and will be addressed in Phase 2 of these proceedings. The proceedings related to the rate reduction bonds have not yet begun. The divestiture proceedings that will reveal the initial market valuation prices for several assets are just in the beginning stages.
As TURN et al. points out, there is no reason that we cannot use the annual transition cost proceedings and monthly reports to anticipate and provide for the necessary acceleration of regulatory assets, should it turn out that write-offs appear imminent. It is reasonable to assume that continuing discussions with the Securities and Exchange Commission (SEC) and various accounting organizations would be necessary before such regulatory assets are considered to be at risk. For example, D.92-12-015 discusses the minutes of a meeting between the SEC and the American Institute of Certified Public Accountants’ (AICPA) Public Utilities Committee, which discussed those agencies’ view of PBOP accruals qualifying as regulatory assets.
"Both DRA’s [the predecessor to ORA] and the utilities’ understanding of what transpired at a meeting between the SEC staff and AICPA Committee are based on incomplete information. However, it is apparent that the SEC has not taken a policy position on what criteria should be used to determine whether a regulatory asset should be allowed or what level of assurance needs to be given by the regulatory agencies.
"We concur with DRA that Commission policy should not be driven by whether or not utilities can record a regulatory asset under Statement 71. Consistent with our position that rate recovery should not be governed by IRS/ERISA requirements, recovery should not be governed by SEC policy or by SEC staff requirements or review." (46 CPUC 2d 499, 521-522.)
While PG&E stated that recent filings before the SEC addressed this issue, these documents were not introduced into evidence. Moreover, although PG&E stated that the overall opinion is that risk and uncertainty prevail, PG&E’s witnesses were not able to state how these conclusions were derived. (TR: 184.) Edison, in its original proposal in this phase, does not propose to accelerate the recovery of regulatory assets and has provided a portion of its September 30, 1996 Form 10-Q submitted to the SEC. In its notes to the Consolidated Financial Statements included in that form, Edison concludes: "Despite the rate freeze, SCE expects to be able to recover its revenue requirement based on cost-of-service regulation during the 1998-2001 time period." (Exhibit 11, Appendix D, p. D-2.) This conclusion is based on Edison’s ability to flexibly apply revenue to Category II costs, as well as Category I costs; that is, Edison states that it can’t allow the Category I account to become too far overcollected at the expense of Category II costs, which could then trigger the write-offs.
In comments to the proposed decisions, ORA has proposed a compromise approach which should address the utilities’ concerns regarding FASB Statement No. 71. We will adopt a 48-month ratable approach to amortizing specific regulatory assets, which may be at risk for write-off because of accounting rules. The determination of which regulatory assets to which this amortization will be applied will be determined after Phase 2 eligibility criteria are resolved. However, if the SEC requires discontinuance of FASB Statement No. 71 for financial accounting purposes, generation-related regulatory assets would remain recoverable through transition cost revenues, to the extent these assets comport with the requirements of § 367.
As the recovery of regulatory assets is accelerated, rate base shall be reduced by the amount of deferred taxes, net of any tax that would be currently due as a result of collecting the regulatory asset.
Section 368(h) refers to PG&E’s Rate Restructuring Settlement of June 12, 1996 as "an example of a plan authorized by this section." According to PG&E, this means that we must accept its proposal for transition cost acceleration, which is consistent with what was filed in this document. In D.96-12-077, we found that because PG&E’s cost recovery plan is substantively different from its June proposal, this example makes it clear that the elements listed in § 368 are not intended to be exclusive nor exhaustive. Furthermore, we stated in that decision that our approval of the cost recovery plans is subject to the following principles:
"To the extent that any element of the plans or of this decision is inconsistent with § 368 or any other provision of AB 1890, the language of the statute prevails. . . .
"The plans vary considerably in their level of detail. Our approval today covers only the general framework for cost recovery outlined in AB 1890 and the details necessary to launch the program for cost recovery. . . . Our approval of the cost recovery plans does not dispose of or prejudge our resolution of issues still under consideration in those proceedings; our decision on those issues will, of course, conform to the statute." (D.96-12-077, mimeo. at pp. 4-5.)
Although PG&E’s cost recovery plan and Rate Restructuring Settlement discussed the acceleration of recovery of generation-related regulatory assets, this must be taken in the context of the statute as a whole and conform to the intentions of that statute. As discussed above, allowing generation-related regulatory assets to be accelerated prior to those assets earning a rate of return does not align the interests of shareholders and ratepayers, nor does it conform to the requirement that transition costs should be recovered as expeditiously as possible.
We are persuaded that recovery of employee-related transition costs which are currently incurred should be allowed to be deferred, in order to mitigate the utilities’ risk of recovering generation-related transition costs. Employees receive protection they might otherwise be lacking because such costs as severance packages, retraining, early retirement, and outplacement which are found to be reasonable are now included in the competition transition charge. In addition, § 375 provides that the costs of employees performing services in connection with § 363 are included as transition costs. Section 363(a) provides, in relevant part, that:
"In order to ensure the continued safe and reliable operation of public utility electric generating facilities, the commission shall require in any proceeding under Section 851 involving the sale, but not spin-off, of a public utility electric generating facility, for transactions initiated prior to December 31, 2001, and approved by the commission by December 31, 2002, that the selling utility contract with the purchaser of the facility for the selling utility, an affiliate, or a successor corporation to operate and maintain the facility for at least two years. The commission may require these conditions to be met for transactions initiated on or after January 1, 2002. The commission shall require the contracts to be reasonable for both the seller and the buyer."
It is apparent that the Legislature anticipated that certain employee-related transition costs might be incurred prior to December 31, 2001. Despite the contentions of various parties that the presumption was that transition costs would be recovered only during the post-2001 period, the Legislature did not adopt language that provided for the deferral of such costs to the extent that these costs reduce the utilities’ opportunities to recover generation-related costs, as it did for implementation costs in § 376. However, because of the concerns for employees delineated in the statute, we will grant the utilities the flexibility to defer recovery of these costs. Consistent with AB 1890, utilities may defer recovery of these costs for later recovery in the period between March 31, 2002 through December 31, 2006.
There has not been a full discussion or development of the record in regard to the interaction of the rate reduction bonds and the transition cost balancing account. Parties have expected that issues addressing rate reduction bonds will be addressed in workshops and in the applications of the IOUs for authority to issue these bonds, including potential ratepayer benefits and the ratemaking mechanisms to prevent costs shifting and to accrue benefits. [ By ruling issued on March 4, 1997 in R.94-04-031/I.94-04-032, ALJ Careaga convened workshops on March 20 and March 21, which were facilitated by the Energy Division. PG&E, Edison, and SDG&E responded to the questions posed in that ruling with a joint filing on March 14, 1997.] Workshops were held on March 20 and March 21 on the necessary elements to be included in the financing applications. There are certain critical issues that we believe should necessarily be determined prior to January 1, 1998, including the treatment of bond proceeds and the corresponding treatment of transition cost property.
Section 840(e) provides that:
"Rate reduction bonds" means bonds, notes, certificates of participation or beneficial interest, or other evidences of indebtedness or ownership, issued pursuant to an executed indenture or other agreement of a financial entity, the proceeds of which are used to provide, recover, finance, or refinance transition costs and to acquire property and that are secured or payable from transition property.
Section 841(e) provides that the Commission has 120 days to process each financing application for rate reduction bonds. It is essential that the details for tracking the bond proceeds and the interaction of the bonds with transition cost property be addressed in such a way so that the expeditious processing of the financing orders is not delayed. We plan to convene workshops in the near future to address these issues.
Using the framework outlined above, we find that the Joint Recommendation is flawed in terms of substantive resolution of the issues addressed. The Joint Recommendation accomplishes little beyond attempting to ensure that potential write-offs are avoided and attempting to interpret the statute. We are not persuaded by this interpretation. As we have previously stated, we cannot abrogate our duty to implement the law in the public interest by allowing the parties to interpret the law for us. The terms of the Joint Recommendation do not conform to the statute. As discussed above, the statute specifically states that transition costs should be recovered as expeditiously as possible.
Only the proposal put forward by TURN et al. and endorsed by FEA and ORA accomplishes this goal. Moreover, this proposal aligns ratepayer and shareholder interests. By requiring that assets with a higher rate of return be amortized prior to assets with a lower rate of return, more revenues become available for actual transition cost recovery. In response to questioning by the ALJ at oral argument, PG&E acknowledged that the magnitude of dollars that must be collected which are associated with utility generation assets are huge compared to dollars that might be deferred into the post-2001 period. "The rate of recovery of these dollars is such that you really wouldn’t know how much needs to be deferred until the very end of 2001 because the dollars are so small relative to the total utility assets. So it does become very difficult to give parties externally or management internally any comfort about what’s going to happen." (TR: 687.)
The Legislature recognized that the utilities had incurred certain costs in conjunction with their obligations to provide reliable service on a nondiscriminatory basis. These transition costs may therefore be recovered, but only to the extent that they are uneconomic in a competitive market, and furthermore, only to the extent that
the net costs of above-market assets exceed the costs of below-market assets. While rates are frozen through December 31, 2001 to collect the majority of these uneconomic costs, the rate freeze is allowed to extend through March 31, 2002 to collect certain transition costs related to exemptions, renewable resource program costs, and BRPU settlement costs, with certain additional provisions. Although the rate freeze ends unequivocally on March 31, 2002, certain transition costs are eligible for recovery after this time period. These include employee-related transition costs (which may be collected through December 31, 2006), restructuring implementation costs (which may be collected until fully recovered), and contractually-incurred power purchase and QF costs in place as of December 20, 1995 (which again may be collected until fully recovered). To the extent that the uneconomic costs can be collected prior to the end of December 31, 2001, the rate freeze will end, and presumably rates will drop. In order to help ensure recovery of transition costs, the 1996 ECAC and ERAM overcollections were credited to offset transition costs; in D.96-12-077, we established that the rate freeze began on January 1, 1997. Finally, there is no recognition that recovery of transition costs is guaranteed; indeed, the utilities are at risk for costs not recovered during the rate freeze.
We will not know the extent to which costs are uneconomic until market valuation is completed (by the end of 2001, as required by § 367(b)). In addition, as PG&E points out, the determination of uneconomic generation assets will depend on the role particular units will play in the new generation market (TR: p. 257). Although it may be relatively easy to calculate the sunk costs (which will be addressed in Phase 2), it will be more difficult to determine the portion of sunk costs that become uneconomic. Presumably, there will be some amount recovered in the Power Exchange prices to cover some portion of the utilities’ fixed costs. While we cannot anticipate those exact amounts, nor what portion of the economic costs would be recovered, it is crucial that we have the ability to track and review this information. Therefore, we must ensure not only that an adequate balancing account is established, so that we can track the recovery of such costs on an asset-by-asset basis (to ensure that we will know when transition costs are fully collected), but also that adequate review is provided to ensure that only the uneconomic portions of these costs are recovered as expeditiously as possible. Despite the utilities’ contentions otherwise, we must necessarily review the utilities’ calculations of the uneconomic portions of generation-related transition costs in order to fulfill our duties under the law; e.g., see § 367(b).
We have not addressed the ratemaking treatment for hydroelectric and geothermal assets, in terms of eligibility for transition cost recovery, the appropriate rate of return associated with these assets, and the interaction of transition cost recovery and generation performance-based ratemaking treatment of such assets. We shall address such issues in Phase 2 of these proceedings and in the generation PBR proceedings. We direct the assigned ALJs to coordinate on these issues.
In order to carry out our statutory obligations, we adopt the following guidelines regarding the transition cost balancing account and the order of acceleration:
1. Certain costs which are currently incurred may be deferred. These include restructuring implementation costs (as addressed in § 376), which may be collected until fully recovered, employee transition costs (as addressed in § 375), which may be recovered through December 31, 2006, and generation-related transition costs which may be displaced by collection of renewable program funding (as addressed in § 381(d)), which must be recovered by March 31, 2002 (see discussion below). Other that these exceptions, current costs should be recovered as incurred, as required by current ratemaking principles and the accounting principle of matching revenues and expenses.
2. Current costs are those cost items eligible for transition cost recovery that are incurred in the current period. The definition of current costs also includes the amortization of depreciable assets on a straight-line basis over a 48-month amortization period. In addition, certain regulatory assets which may be jeopardized by write-offs should be amortized ratably over a 48-month period. The specific regulatory assets to which this guideline applies should be determined once Phase 2 eligibility criteria is resolved. The amortization of the investment-related assets should include a
provision for associated deferred taxes and the reduced rate of return called for in the Preferred Policy Decision. [ We note that D.96-12-083 authorizes Edison to accelerate amortization for Palo Verde on a 60-month period (1997-2001). Each utility’s tariffs should conform to specific depreciation periods that may have been adopted for the various nuclear facilities.] In order to accommodate on-going market valuations and accelerated recovery, the utilities should recalibrate recovery levels for remaining months of the schedule, if necessary. To the extent that revenues do not cover costs in a current period, revenues should be applied first to costs incurred during that period and then to scheduled amortization, including that of regulatory assets.
3. To the extent that any additional headroom revenues remain and until such time as plants are depreciated to their anticipated market value, any additional revenues should be applied first to accelerate the depreciation of those transition cost assets with a high rate of return and in a manner which provides the greatest tax benefits. In this way, accelerated recovery of transition costs will benefit shareholders and ratepayers.
4. As assets which are currently included in rate base are amortized, rate base should be reduced correspondingly on a dollar for dollar basis, including the impact of associated taxes. (TR: p. 267.) This will ensure that the utilities are in compliance with § 368(a) which requires among other things that transition costs be amortized such that the rate of return on uneconomic assets does not exceed the authorized rate of return.
5. As a general guideline for those assets subject to market valuation, generation-related assets should be written down to their estimated market value, but not below, based on a relatively broad estimate of market value. We will be somewhat flexible in applying this guideline. We recognize both PG&E’s and Edison’s concerns that public disclosure of such estimates could adversely affect the auction process and will address the need for protective orders and confidentiality as the need arises. It is not our intent to revisit the market valuation process occurring in other proceedings.
6. It is the duty of the Commission to determine what transition costs are reasonable and because such costs cannot be determined to be uneconomic or not until we have more information, we reject the utilities’ request for complete flexibility in managing their transition cost recovery. We require monthly and annual reports and will institute an annual transition cost proceeding, separate from the Revenue Adjustment Proceeding. In D.96-12-088, we provided that authorized revenues would be established in the respective proceedings for various issue areas and would be consolidated in the Revenue Adjustment Proceeding. In addition, to provide further clarity to this concept, we will require the utilities to revise their pro-forma tariffs to indicate that the cost accounts and subaccounts they establish are not labeled as transition cost subaccounts, but are merely the sunk costs accounts and subaccounts. This is important because we will establish the sunk costs in Phase 2 of these proceedings, but the uneconomic portion of these costs (which is the portion eligible for transition cost recovery) must be established on an ongoing basis.
7. To the extent feasible, current costs, including those categories which may be deferred, should be recovered before December 31, 2001. We expect that the deferred transition costs should be small relative to the transition costs incurred from QF contracts and amortizing nuclear assets. Restructuring implementation costs and employee-related transition costs may be deferred with interest at the usual 90-day commercial paper rate. Generation-related transition costs which are deferred because of funding the programs addressed in § 381(d) shall not accrue interest.
8. To the extent possible, the utilities should manage acceleration of assets to achieve a matching of revenues to current costs plus the portion of noncurrent costs that is accelerated, in a manner to avoid major under- or over-collections of CTC. To the extent that noncurrent costs are accelerated, the utilities should recalibrate the remaining months of the recovery schedule to adjust the depreciation schedule through the end of the transition period. To the extent that over- or under-collections occur, interest will accrue at the usual 90-day commercial paper rate, with the exception of deferred generation-related transition costs displaced because of funding the § 381(d) programs.
These guidelines will allow us to track and review the transition costs appropriately during the rate freeze period. Adopting this very pragmatic application of the policy established in the newly added PU Code sections does not violate the bargains addressed in AB 1890, as several parties allege; rather, this implementation balances the interests of shareholders, ratepayers, and employees in a manner that is consistent with current ratemaking practices as well as AB 1890.
We decline to give the utilities the flexibility they seek in determining the appropriate market value for purposes of accelerating depreciation to anticipated market value. However, we acknowledge the utilities’ concerns with lengthy, protracted hearings and a detailed administrative approach. We will therefore convene workshops to consider how to apply the guidelines adopted in this decision and the potential for streamlining the annual transition cost proceedings.
It is reasonable to require PG&E, Edison, and SDG&E to establish transition cost balancing accounts with a Revenue Account, Current Costs Account, Accelerated Costs Account, and Post-2001 Eligible Costs Account, as all of the utilities now agree. Each utility should establish appropriate subaccounts. Furthermore, all parties agree that, to the extent that headroom is available, revenues are applied first to the Current Costs Account, which should include any currently incurred cost, including costs associated with irrigation district exemptions and renewable programs. Transition costs associated with restructuring implementation costs and employee-related transition costs that are incurred currently may be recorded in the Post-2001 account.
PG&E, Edison, and SDG&E should file and serve pro forma transition cost balancing account tariffs based on these general guidelines and which are in compliance with other Commission decisions in this area. [ For example, Edison should include language in its tariffs which is in compliance with the SONGS decisions (D.96-01-011 and D.96-04-059) and the Palo Verde decision (D.96-12-083). When we adopt a ratemaking methodology for Diablo Canyon, PG&E should similarly update its pro-forma tariffs. Tariffs should reflect findings adopted in this and any other restructuring-related decisions; otherwise, pro-forma tariffs should reflect the utilities’ proposals in various issue areas.] Workshops will be convened in the summer to address specific issues that may arise in the implementation of these tariffs as we work through the Phase 2 issues. We anticipate that workshops also will be convened after the Phase 2 decision is issued to address remaining issues associated with the balancing account tariffs.
Parties have agreed that the CTC will be calculated as a residual calculation, or the difference between frozen rates and the sum of all rate components, including the Power Exchange price, as discussed above. Under this approach, customers with frozen rates might not benefit from lower Power Exchange prices through lower rates, but would instead receive a benefit because these lower Power Exchange prices would result in increased headroom. We have approved this approach in D.96-12-077, in which we explained that the headroom revenues consist of the difference between recovered revenues at the frozen rate levels (including the reduced rate levels for residential and small commercial customers) and the reasonable costs of providing utility services. As previously stated, it is essential that transition cost recovery be tracked accurately, so that we will know when recovery is complete, and if transition cost obligations are completed before March 31, 2002, the rate freeze may end early. [ Accurate tracking and review will also allow the Commission to be in a position to expeditiously institute the types of proceedings that might be necessary to insure that rates will change when the rate freeze ends.] During the Energy Division workshops, described more fully below, participants discussed the requirement in D.96-12-077 which provides that the interim transition cost balancing account include subaccounts for each rate schedule, tariff option, and contract so that revenues may be tracked at this disaggregated level. The purpose of establishing this level of detail is to track the transition cost contributions of the customers of each rate group so that we will know when these groups have paid their fair share of transition costs, pursuant to § 367(e)(1).
During the workshop, participants disagreed with the idea of applying these very specific subaccounts to the final transition cost balancing accounts. The utilities asserted that this kind of detailed tracking is not possible, because the cost allocation information is only disaggregated to the rate group level. The utilities contend that obtaining this information would require them to design a study, install meters to obtain a representative sample of customers’ use, and then collect the data for two years. Workshop participants agreed with the utilities that the current application of Equal Percentage of Marginal Cost (EPMC) methodology does not allocate costs to this detailed level.
In addition, short of some differences in collection periods due to customers on each side of the firewall bearing different exemption costs, participants agree that because of the residual calculation of CTC, there can be no pre-determined CTC obligation by customer class. Workshop participants assert that as long as there are outstanding transition cost obligations, all customers must share these obligations according to their EPMC shares. All customers pay down the aggregate transition cost obligation through the residual CTC recovery in their bills until the aggregate transition cost obligation is paid off. At that point, each group on each side of the fire wall will continue to pay off the accrued exemption amount for its group, until that amount is recovered, but no later than year-end 2001, with the exception of the provision for irrigation district exemptions. Under this interpretation, no customer will satisfy its transition cost obligation sooner than another customer. Parties agreed that transition cost tracking should take place at the rate group level.
This decision adopts a procedure for tracking transition costs and does not address allocation, which will be determined in the unbundling and ratesetting proceeding (A.96-12-009 et al.) We recognize the difficulties associated with tracking transition cost obligations at a level of detail greater than the rate group level, and agree that tracking at the rate group level appears to be the most practical alternative. We will therefore expect utilities to track transition cost obligations and payments at this level of detail. Section 367(e)(i) requires that transition costs be allocated among the various classes of customers, rate schedules, and tariff options to ensure that costs are recovered "in substantially the same proportion as similar costs are recovered as of June 10, 1996, through the regular retail rates of the relevant electric utility…" We are satisfied that tracking CTC revenues and transition cost recovery at the rate group level, together with the rate unbundling process and the implementation of the fire wall memorandum accounts should ensure that the requirements of § 367(e) (1) are met. Rate groups are the fundamental units for which marginal cost revenue responsibility and allocated revenue are determined. As such, rate groups are aggregations of related tariff schedules (default and optional), and disaggregations of customer classes. For example, the large power customer class consists of several rate groups. Issues related to allocation of transition costs and any potential for certain customers to pay off transition cost obligations faster than others will be addressed in our unbundling and ratesetting proceeding, A.96-12-009 et al., and we direct the utilities to address these issues in crafting and updating CTC tariffs for direct access and full service customers once a decision is rendered in that proceeding. [ By ruling issued January 31, 1997 in A.96-12-009 et al. , the assigned ALJ provided that the ratesetting implications of the virtual direct access option would be addressed in that proceeding. The following example may help to illustrate the issue involved: Under frozen rates, one customer may consume energy primarily in off-peak periods. In these periods the Power Exchange price is low and headroom is larger, meaning that a significant portion of this customer’s bill would be applied to CTC revenues. Another customer may consume more energy on peak when the Power Exchange price is higher. A higher Power Exchange price reduces the amount of revenues available for the CTC, so that the CTC payment is only a small percentage of this customer’s total bill. ]