In this decision we review and approve the cost recovery plans of Pacific Gas and Electric Company (PG&E), Southern California Edison Company (Edison), and San Diego Gas & Electric Company (SDG&E). The utilities were directed to file these plans by Public Utilities (PU) Code § 368, enacted as part of Assembly Bill (AB) 1890 (Stats. 1996, Ch. 854), which was signed by Governor Wilson on September 23, 1996. The plans propose a framework for the utilities' recovery of certain costs that would otherwise be rendered unrecoverable by the move from regulation to competition in the electric utility industry that we outlined in our Policy Decision (Decision (D.) 95-12-063, as modified by D.96-01-009) and that the Legislature endorsed in AB 1890. The plans and this decision also describe how ratemaking will be accomplished during the early stages of the transition to competition.
Section 368(1) requires regulated electric utilities to propose cost recovery plans for the recovery of uneconomic costs of the utility's generation-related assets and certain other transition costs. If these plans meet specified criteria, the Commission is required to authorize them. In very general terms, the criteria include:
Section 368(h) cites PG&E's "Restructuring Rate Settlement" of June 12, 1996 as an example of a plan authorized by § 368, although 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 intended to be neither exclusive nor exhaustive. The proposed plans accordingly include other elements.
In compliance with the Coordinating Commissioner's Ruling of September 30, 1996, PG&E, Edison, and SDG&E filed their cost recovery plans on October 15. An Administrative Law Judge's Ruling of October 23 set a schedule for comments. California Industrial Users; the Energy Producers and Users Coalition and the Cogeneration Association of California, jointly; the California Large Energy Consumers Association and the California Manufacturers Association, jointly; the Office of Ratepayer Advocates (ORA); and The Utility Reform Network (TURN) filed comments on November 8. Edison, PG&E, and SDG&E filed reply comments on November 18.
Section 368 is cast in mandatory language: Each utility "shall propose" a plan to recover costs, and the Commission "shall authorize" the utility to recover the costs if the plan meets certain criteria. This mandatory language, however, does not entirely remove the Commission's discretion with regard to these plans. Our function in relation to these plans is not a merely ministerial one of checking the plans against the listed criteria and stamping our approval if all elements are in place. The criteria specified in § 368, with some exceptions, provide only the broad framework for cost recovery. The utilities' plans provide more detail, filling in some of the gaps in the statutory framework and adding desired elements. Our role includes, among other functions, coordinating the legislative requirements with our existing proceedings that are considering the issues implicated by § 368, and critically reviewing the utilities' additional proposals for consistency with the goals expressed in AB 1890 and in our Policy Decision. Our general role is to approve the overall framework for recovery of transition costs and to provide necessary guidance on some of the details of this cost recovery.
For these reasons our approval of the plans is subject to the following principles:
The subsections of § 368, which set forth the criteria that the plans are required to meet, can be grouped under three large topics: the mechanics of cost recovery and ratemaking during the cost recovery period (subsections (a), (d), (f), and (h)); provisions relating to individual utilities (subsections © and (e)); and rate unbundling (subsection (b)). In this decision we will address each of these topics, but we will devote primary attention to the first subject, the mechanics of cost recovery and ratemaking during the initial stages of the recovery period. This is an area characterized by both vital importance and current uncertainty, and we hope to describe as clearly as possible exactly how ratemaking and cost recovery will interact over the next few years. For reasons of expediency, we will be particularly concerned about ratemaking and cost recovery during 1997.
The cost recovery strategy outlined in AB 1890 and in the utilities' plans depends on two elements: a freeze of rates at the levels in effect on June 10, 1996, and an expectation that the utilities' costs of providing service will decline from the levels producing the June 10 rates. Freezing rates stabilizes collected revenues (subject to sales variations), and declining costs create "headroom," i.e., revenues beyond those required to provide service, that can be applied to offset transition costs. The utilities' reasonable costs of providing service are currently identified as their authorized revenue requirements. Authorized revenue requirements are expected to decline in the near future for various reasons, including the acceleration of the depreciation of the San Onofre Nuclear Generation Station (SONGS) Units 2 and 3 owned by Edison and SDG&E, the end of the fixed price period for many power purchase agreements with qualifying facilities (QFs), the availability of inexpensive purchased power available for import, and the continuation of low inflation rates. For example, the authorized revenues of PG&E, which presented the outline of AB 1890's recovery strategy in the Restructuring Rate Settlement cited in § 368(e), would have declined by over $500 million in 1997 primarily due to a lower revenue requirement for its forecasted Energy Cost Adjustment Clause (ECAC) expenses. With collected revenues stabilized by the rate freeze, the forecasted decrease in revenue requirements creates headroom revenues that may be used to offset transition costs.
In addition, § 368(a) jump-starts the collection of transition costs by requiring any overcollections recorded in the utilities' ECAC and Electric Revenue Adjustment Mechanism (ERAM) balancing account as of December 31, 1996, to be credited toward transition cost recovery. AB 1890 does not explicitly require overcollections after December 31 to be credited toward transition cost recovery, but it is consistent with the spirit of the statute and the Restructuring Rate Settlement cited approvingly in § 368(h) to do so. The plans propose the continuing crediting of headroom revenues, and we agree with this approach.
The portion of the utilities' costs that will remain subject to this Commission's authorization will decline as we complete the current round of restructuring. By 1998, recovery of transmission costs will be overseen by the Federal Energy Regulatory Commission (FERC), and generation-related costs will increasingly be recovered through the Power Exchange. For simplicity, in this decision we refer to all costs of providing utility service as the authorized revenue requirement, but our use of this term should not be read as any failure to recognize the changes in cost recovery that restructuring will bring.
Section 368(a) requires the cost recovery plans to "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." This simple statement has complex and significant implications.
The statute requires the cost recovery plans to set rates equal to the level shown on rate schedules in effect on June 10. Since the signing of AB 1890, the question whether other tariff or contract terms could be changed as long as the rate was not affected has been raised by utilities' proposals to close specific rate schedules to new customers. By referring only to a freeze of rates, § 368(a) implies that as long as the schedule remains in the tariffs for existing customers and the rate is not changed, closing the schedule to new customers is not prohibited. (Of course, the Commission may choose to reject this or similar proposals on other grounds.)
Rates are frozen at the levels shown on the rate schedules as of June 10, 1996. The effect of § 368 is to set aside any Commission-authorized rate changes that had not yet been reflected in the rate schedules as of June 10. Moreover, after the rate freeze takes effect, alterations to the rate levels incorporated in the June 10 rate schedules are also apparently prohibited. This does not necessarily mean, however, that the Commission may not make adjustments to the components of that rate level. The separation of rate components described in § 368(b) would be meaningless if the Commission did not have this ability. Thus, within the level of the frozen rate the Commission retains the ability to adopt rate components that differ from the specific rate components in effect on June 10, subject to the fire wall and proportional cost recovery required by § 368(e)(1) and the prohibition on cost-shifting of § 368(b). The Commission may also authorize new optional rate schedules and tariffs reflecting changing circumstances (§ 378), as we discuss below.
No commencement date was specified in the legislation. The utilities attempted to implement the rate freeze immediately by filing advice letters freezing rates, but our staff correctly returned the advice letters. Section 368 does not directly authorize a rate freeze, as the utilities apparently assumed; it authorizes the utilities to submit plans proposing a rate freeze. The statute contemplates action by the Commission on the plans, and thus the date the freeze takes effect depends on our action. Under the circumstances, it makes sense to begin the freeze on January 1, 1997, and the utilities are authorized to file compliance advice letters to that effect. Edison and SDG&E may refile the material presented in Advice Letter (AL) 1187-E and AL 998- E, revised as necessary to reflect the requirements of this decision. PG&E's rates have apparently not changed since June 10, and no further filing by PG&E is needed to effect the freeze.
Section 368(a) requires the utilities' plans to include a rate reduction of at least 10% for small commercial(2) and residential customers.(3) This reduction is "for 1998 and continuing through 2002." We construe the term of this reduction to be from January 1, 1998 to March 31, 2002, if the rate freeze is not terminated earlier. The latter date is specified elsewhere in § 368(a) as the end of the rate freeze.
AB 1890 allows the utilities the option of accomplishing the required rate reduction by issuing rate reduction bonds, as described in §§ 840-847. The proceeds from the bonds will be used to "provide, recover, finance, or refinance" transition costs (§ 840(e)) in order to lower rates for residential and small commercial customers (§ 841(a)). Revenues from these customers will then be used to pay off the bonds (§ 841(a)). The net effect is to defer collection of some of the transition costs allocated to residential and small commercial customers from the recovery period ending no later than March 31, 2002, to a period ending when the bonds are paid off. Issues concerning the relation between bond proceeds and transition cost recovery will be considered in our transition cost proceeding, A.96-08-001 et al.
As specified in § 368(a), the rate freeze, including the reduced rate for residential and small commercial customers, will continue in effect until Commission-authorized transition costs have been fully recovered, but no later than March 31, 2002. The recovery of transition costs terminates on December 31, 2001, subject to exceptions listed in § 367(a). However, the recovery period can be extended to March 31, 2002 to allow for recovery of certain specified costs. (§ 367(a).)
After the termination of the freeze, the utility will absorb, with certain exceptions, any transition costs that were not recovered during the freeze. Rates after the freeze may include recovery of certain transition costs, for limited periods: the uneconomic portion of continuing power purchase obligations (§ 367(a)(2)), employee-related transition costs (§§ 367(a)(1), 375), the costs of incremental cost incentive plans for SONGS (§ 367(a)(4)), and generation-related plant and regulatory assets in an amount equal to the unreimbursed costs of implementing direct access, the Independent System Operator (ISO), and the Power Exchange (§376).
Section 378 allows the Commission to authorize new optional rate schedules and tariffs "that accurately reflect the loads, locations, conditions of service, cost of service, and market opportunities of customer classes and subclasses." The ability to fit new services and options to changing market conditions will be particularly important after direct access becomes available.
AL 1196-E, recently filed by Edison, raises several points related to the policies of the Commission and AB 1890 with regard to new schedules and options. Edison's advice letter asks us to remove a notice provision from its Spot Pricing Amendment and Incremental Sales Rate Agreements of Schedules I-6 and TOU-8-CR-1 to comply with AB 1890. The notice provision was required by D.96-08-025 and would have closed the schedules effective January 1, 1998.(4) Section 368(a), however, imposes a rate freeze that requires Edison to maintain rates to existing customers under these schedule for the duration of the rate freeze.
We agree with Edison's narrow request to remove the notice provision, and AL 1196-E will become effective as of January 1, 1997. However, after 1997 other aspects of these schedules will run afoul of AB 1890 and our Policy Decision. D.96-08-025 identified the potential of these schedules for shifting costs to other schedules, because they encourage the purchase of on-peak energy at prices which may vary from the Power Exchange price. AB 1890 echoes our Policy Decision's prohibition of cost-shifting. In addition, the pricing provisions of these schedules are not tied to the Power Exchange price, and therefore they could result in customers' paying a mark-up of the Power Exchange price. Our Policy Decision prohibits utilities from pricing energy at more than the Power Exchange price (Policy Decision, Conclusion of Law 19, slip op. at 205-206), and nothing in AB 1890 contradicts this prohibition. Thus, by the start of the Power Exchange in 1998, Edison will need to reconcile the requirements of the freeze with our prohibition of mark-ups above the Power Exchange price for customers served under these agreements, and until we have approved that reconciliation, Edison is not authorized to offer those schedules to new customers in 1998.
To the extent that the pricing provisions of these agreements resemble contracts for differences, they are subject to Commission review. The Commission's prohibition of contracts for differences between utilities and their own or affiliated generation facilities (Policy Decision, slip op. at 81) was unaffected by AB 1890.
Customers are currently allowed to change the rate schedule under which they receive utility service, or to "migrate," if they meet the requirements of the other schedule. (Service under new schedules is addressed above.) As we have discussed, the freeze applies to rate levels, and customers are not bound by the freeze to the schedules under which they were served on June 10, 1996.
To determine whether and when the rate freeze terminates due to full recovery of authorized transition costs, it will obviously be necessary to keep track of both authorized transition costs and the revenues applied to offset them. Edison and SDG&E have filed advice letters requesting authority to establish interim transition cost balancing accounts (TCBAs) for the limited purpose of holding ECAC and ERAM overcollections as of December 31, 1996, and the tariffs establishing these accounts will take effect on January 1, 1997. PG&E should file a similar request to establish an interim TCBA. (PG&E's AL 1607-E presented a similar proposal, but did not include tariff language to accomplish this.)
In this decision we expand the function of these interim TCBAs beyond the limited purpose Edison and SDG&E proposed. The interim TCBA will record for each utility the difference between revenues collected under the frozen rates and the adopted consolidated revenue requirement of the utility. As we discuss in the next section, the interim TCBA should be revised to contain separate subaccounts for each rate schedule, tariff option, and contract. The interim TCBA will continue to be a temporary holding account for ECAC and ERAM overcollections as of December 31, 1996.
The interim nature of these accounts will eventually be removed after we have considered refinements to these accounts in Application (A.) 96-08-001 et al. In that proceeding, we will resolve the issues related to tracking both the transition costs we authorize for recovery and the headroom revenues, i.e., the difference between revenues collected at frozen rates and the authorized revenue requirement. The resulting, more refined TCBA will be the hub of transition cost recovery and ratemaking during the recovery period.
Since rates for each customer class are frozen, revenues will be allocated essentially as they were on June 10. Preserving the June 10 revenue allocation corresponds on the revenue side to § 367(e)(1)'s directive that transition costs are to be allocated among the various customer classes, rate schedules, and tariff options, and recovered from these categories "in substantially the same proportion" as similar costs were recovered in retail rates on June 10, 1996. In a similar vein, § 367(e)(1) also sets up a "fire wall" segregating the recovery of costs associated with exemptions from the competition transition charge (CTC) between the combined class of residential and small commercial customers, on the one hand, and the combined class of all other customers, on the other.
To comply with the fire wall requirement, the utilities will also need to record the costs associated with the CTC exemptions provided in §§ 372, 373, and 374. Recovery of the costs of CTC exemptions from the broad fire wall categories creates a possible exception to the preservation of the June 10 revenue allocation, but we will consider that issue in our unbundling proceeding.
To preserve our options for recovery of the costs of CTC exemptions and to carry out the principle that transition costs should be allocated and recovered within each rate schedule, tariff option, and contract, it will be necessary to set up subaccounts for each rate schedule, tariff option, and contract within the interim TCBA.
The interim TCBA will keep track of transition cost recovery by debiting the transition costs that the Commission authorizes for recovery, and crediting collected headroom revenues. As we mentioned above, a separate subaccount will need to be established for each rate schedule, tariff option, and contract to allow for an assignment to those classifications of transition cost responsibility and to enforce the fire wall for recovery of the costs of exemptions from CTC.
The issue of identifying and quantifying recoverable transition costs will be addressed in A.96-08-001 et al. We note here that some of the debits may be estimates, particularly at the early stages of transition cost recovery. These estimates will be trued up with recorded or verifiable figures as the recovery proceeds. In addition, due to the crediting of ECAC and ERAM overcollections as of December 31, 1996 (§ 368(a)) and a lag in quantifying recoverable transition costs, it is possible that in the earlier stages of the recovery period the timing of entries to the interim TCBA will have a variable quality that should not be misinterpreted as indicating either an excess or shortfall of transition cost collection. Any momentary surplus will not trigger the end of the rate freeze.
In general, 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 beginning in 1998) and the reasonable costs of providing utility services, which for convenience we refer to as the authorized revenue requirement. A utility's authorized revenue requirement has three general components: the base revenue requirement; the fuel- related revenue requirement, including purchases (ECAC); and other balancing account revenues. The nature of the authorized revenue requirement will continue to change as we move toward a more competitive industry. It is worthwhile to consider how the three general components of authorized revenues will fit into the calculation of headroom revenues.
Base revenues are intended to cover operation and maintenance expense (excluding fuel expense), depreciation expense, taxes, and return on invested capital. Base revenue requirements are currently set in each utility's general rate case (GRC) or performance- based ratemaking (PBR) proceeding.
For those utilities under GRCs, authorized base revenues will be those authorized for each year in the GRC, with one important modification. Base revenues include a return on undepreciated rate base. One of the functions of the utilities' cost recovery plans is to accelerate the depreciation of generation units that may be uneconomic in a competitive generation market.(5) As the generation portion of rate base is depreciated at a faster rate than assumed in the GRC, the associated revenue requirement must decline; otherwise, the rate of return on the generation-related rate base will rise above its authorized level. Section 368(a) discourages this result: "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." Thus, the authorized revenue requirement must be adjusted periodically to account for accelerated depreciation of generation rate base.
PBRs present a different set of issues. In general, PBRs attempt to give the utility a financial incentive to control and lower costs and to increase revenues. In a simple version of a PBR, this incentive is created by setting a benchmark level of performance (i.e., expected costs and revenues) and allowing the utility to retain gains or bear losses (net revenues measured against the benchmark) within a certain range of outcomes (the deadband). When the outcomes fall outside that range, the resulting extra gains or losses are shared between ratepayers and shareholders.
As long as performance falls within the deadband, PBRs can be integrated well with the cost recovery strategy and the interim TCBA. Under these circumstances, we would set the base revenue requirement at the level associated with the benchmark level of performance, and the utility would gain or lose in relation to its performance, as we intended when we authorized the PBR.
When the utility's performance results in shared gains or losses, however, the incentives that PBRs are intended to promote become somewhat distorted under the cost recovery strategy of AB 1890 and the utilities' plans. Because of the rate freeze, the utility receives the same amount of total revenue, regardless of its performance. We can affect only the allocation of collected revenues between authorized revenue requirement and headroom revenues. But if we attempt to "reward" the utility for excellent performance by raising the authorized revenue requirement, we have created an equal and opposite "punishment" for ratepayers by increasing the authorized revenue requirement (the former basis for rates) and decreasing the headroom revenues available to offset transition costs. Conversely, if we attempt to share losses by lowering the authorized revenue requirement, shareholders will nevertheless benefit from the resulting increase in revenues available for transition cost recovery.
Another option is not to adjust the authorized revenue requirement to simulate sharing, but to retain the benchmark assumptions as the base revenue component of authorized revenue requirement. This approach has the virtue of simplicity, but would result in unanticipated gains and losses for the utility when performance would otherwise result in sharing.
Thus, it is not possible to replicate exactly the intended incentives of PBRs under the interim TCBA when shared gains or losses are involved. We would like to preserve as much as possible the intended incentives of the PBR, but the best way to accomplish this goal is not immediately obvious. We will consider these issues more specifically in our proceedings on generation PBRs, A.96-07-009 et al. These issues should also be considered in relation to the currently authorized PBRs. For SDG&E's PBR, these issues should begin to be considered in the midcourse correction for the base rate mechanism. For Edison's recently authorized transmission and distribution PBR, parties should examine these issues as the PBR is implemented.
The annual cost of capital filings adjust the authorized rate of return on rate base for the utilities.(6) As long as facilities remain in rate base, the need for a cost of capital proceeding, or some other method for accounting for changes in the cost of money, will continue. The effect of any cost of capital adjustment will be to alter the authorized revenue requirement.
The role of operational attrition has diminished in recent years. Among other things, it formerly was used to make adjustments to rate base, an important function during times when electric utilities were regularly adding generation units and major transmission facilities to their systems. Under the cost recovery plans, the function of making adjustments to rate base will resume its importance, because the accelerated depreciation of generation units will have a substantial and not entirely predictable effect on base rate revenues. As part of the annual Revenue Adjustment Proceeding, discussed below, we will adjust the utilities' rate bases to reflect the pace of depreciation of rate base plants.
As specified in § 368(a), any overcollections recorded in the ECAC and ERAM balancing accounts as of December 31, 1996 will be credited to the interim TCBA.
For 1997, authorized ECAC revenues will continue to be a part of the authorized revenue requirement. The balancing function of ECAC will operate somewhat differently as a result of the rate freeze. If ECAC costs are higher than forecasted, then authorized revenues will be insufficient to cover these costs, and the resulting "undercollection" will eventually result in a higher authorized revenue requirement (assuming the costs are reasonable and subject to the rate freeze). Since rates may not rise to amortize the undercollection, however, the effect is to reduce the headroom revenues available for crediting to the interim TCBA. Similarly, if ECAC costs are lower than forecasted, a larger headroom and greater credit to the interim TCBA will result.
In 1998 and subsequent years, the Power Exchange price will set the standard for electric generation and power purchases, the primary components of ECAC costs. Certain excess costs, such as those associated with power purchases or the cost of generation needed for reliability and transmission support, will be accounted for as additional transition costs. The functions now provided by ECAC may become in effect a matter of bookkeeping, tracking authorized revenues (i.e., the costs of energy as measured by the Power Exchange prices) and additions to transition costs (i.e., energy-related costs in excess of the Power Exchange price).
It is not clear at this time that the sales forecast developed in conventional ECAC proceedings will be needed. The forecast is used to convert authorized revenue requirement into rates, but since rates will be frozen, this function will no longer be needed. We may, however, still need a forecast of systemwide retail sales for 1998 and beyond to calculate the CTC for direct access customers.
The remaining revenue requirement results from adjustments to a number of balancing accounts. The primary balancing account, other than ECAC, is the ERAM, but Edison, for example, also has accounts for California Alternate Rates for Energy (CARE), demand-side management, research, development and demonstration, and economic development discounts.
The original purpose of ERAM was to control for sales fluctuations, so that the utility's recovery of its base revenue requirement was not tied to its achieving the forecasted level of sales. In particular, the Commission established ERAM to counter the utility's economic disincentive to support demand-side management (DSM) and other ways of improving the efficiency of energy use. Successful DSM and efficiency programs decrease sales and, in the absence of ERAM, revenues. When sales are lower than forecasted, ERAM records the resulting shortfall in revenues, and the Commission adjusts subsequent rates to amortize the undercollection, usually during the following year. The same sort of adjustment is also made for other sources of sales fluctuation, including weather, business cycles, and forecasting error. The mechanism also operates when sales are higher than forecasted to prevent inflated utility earnings.
The rate freeze and the cost recovery plans will have several significant effects on ERAM.
First, the accelerated depreciation and divestiture of generation assets will shrink the generation-related rate base, and the remaining rate base will largely consist of transmission and distribution assets.
Second, the rate freeze will indirectly supplant some of ERAM's function of controlling for sales variation. As long as headroom exists, i.e., total collected revenues exceed authorized revenue requirement, the utility will collect its exact authorized revenue requirement, including base revenues. All other collected revenues (the headroom) will be allocated to transition cost recovery, with the exception of refunds. Variation in sales will affect only the amount of the allocation to headroom: higher sales result in greater offsets to transition costs, and lower sales mean lower offsets.
Third, the introduction of competition for generation will render ineffective our past approach of supporting DSM by using ERAM to counter the utility's economic incentive to increase sales. Many companies other than the utilities will be in the business of selling energy at retail, and we have no inclination to thwart their desire to compete. In anticipation of these market realities, we have shifted our emphasis in the area of DSM toward creating positive financial incentives for the utilities to carry out effective and efficient DSM programs (the Annual Earnings Assessment Proceeding). We discussed the implications of the restructured industry in the Policy Decision and suggested that continued financial incentives should be concentrated on market transformation and education. (See Preferred Policy Decision, slip op. at 155-156.) We also urged the Legislature to consider adopting a nonbypassable surcharge applied to retail sales to fund energy efficiency programs. (Id. at 157.) AB 1890 requires such a surcharge. (§§ 381(b)(1), 381(c)(1), 385(a)(1).)
At the same time, we have recognized the need to continue to adjust base revenues to account for the effects of DSM and energy efficiency programs. Our recent decision on Edison's nongeneration PBR, for example, ordered Edison to develop such an adjustment. (D.96-09-092, slip op. at 34-35.) At least until the nonbypassable surcharge is in place, we will need to continue to make an adjustment to base revenues to account for the effects of DSM and energy efficiency programs. Our efforts to improve the measurement and evaluation of DSM programs will aid in this effort. Issues relating to how to measure DSM effects in the new industry structure the mechanics of making this adjustment will be addressed in the rate setting area of this proceeding.
ERAM has also picked up other functions over the years, including accounting for electric vehicle program costs, intervenor compensation, and the reimbursable costs of consultants hired by the Commission in connection with utility applications. It has also become a convenient way of returning refunds and shared revenues to ratepayers.(7) The ratemaking changes brought on by AB 1890 and the move to competition may make some of these auxiliary ERAM functions unnecessary, or may require us to find a different way to continue any functions that are still needed. In Advice Letter 1005-E, SDG&E recently proposed to eliminate a number of balancing and memorandum accounts, including the ERAM. We will not act on SDG&E's proposal by December 31, 1996, as requested, but we will use SDG&E's proposal as a focus for considering whether and how to continue ERAM's auxiliary functions and whether to eliminate the accounts SDG&E has targeted. We direct the Energy Division, in coordination with the Assigned Commissioner in the rate setting issue area, to hold workshops, open to all parties and the other utilities, to address the issue of streamlining the tariffs and accounts, using SDG&E's proposal as a framework. The Energy Division should report back to us with the recommendations resulting from that process by March 31, 1997. In the meantime, utilities should continue to track credits and debits for these auxiliary items in the ERAM. Any net credits will be addressed in the Revenue Adjustment Proceeding, discussed below.(8)
As the preceding discussion makes clear, many of the functions of our existing proceedings diminish or disappear due to the operation of the cost recovery strategy mapped out in AB 1890 and the utilities' plans. To streamline our proceedings while retaining our ability to carry out our remaining ratemaking obligations, we will establish a new annual proceeding, the Revenue Adjustment Proceeding (RAP) to consolidate pending changes in authorized revenues and to track revenues collected at frozen rate levels. Authorized levels of revenue requirement will be established in other proceedings and consolidated in the RAP. Certain details of the RAP will be discussed in our revision of the Roadmap first outlined in D.96-03-022.
Each utility indicated in its cost recovery plan that it planned to file an Advice Letter to establish an Industry Restructuring Memorandum Account (IRMA) to record costs associated with electric restructuring. The Energy Division asked the utilities to prepare draft Advice Letters and Preliminary Statement language to implement the IRMA and to submit the resulting proposal as a supplement to the cost recovery plans. The supplements were filed on November 8.
Each utility recommends establishing nine primary subaccounts in IRMA. All utilities recommend the following eight subaccounts:
PG&E also proposes a subaccount for Bidding Company Contract Costs, while Edison and SDG&E propose a subaccount for Other Industry Restructuring Related Costs.
We discuss each subaccount below.
PG&E's draft Preliminary Statement language for this subaccount is complete and consistent with § 375. In their compliance filings, Edison and SDG&E should use PG&E's language. Section 375 limits recoverable employee-related transition costs to "severance, retraining, early retirement, outplacement and related expenses for the employees" and excludes costs associated with "officers, senior supervisory employees, and professional employees performing predominantly regulatory functions." We further note that recoverable costs include only costs resulting from restructuring, and not similar costs arising from other aspects of the utility's business strategy. The utilities should be prepared to demonstrate that the costs recorded in this subaccount fall within these limitations.
At this time, establishment of a subaccount to recover costs associated with implementation of direct access, as described in the draft Advice Letters, is premature. We currently have before us several policy issues related to direct access that may determine whether or not certain costs are associated with the utilities' implementation of direct access. For example, we are considering whether we should adopt standards for real-time pricing metering equipment that would lead to competitive provision of metering service.
Also, on November 26, PG&E, SDG&E, and Edison submitted joint comments requesting approval of a Consumer Education Plan (CEP) and the hiring of a consultant to further develop and implement the CEP. The CEP was recommended in the Consumer Protection and Education Report filed by the Direct Access Working Group on September 30, 1996. The utilities also request recovery of the incremental costs associated with CEP development and implementation.
We agree that a subaccount for CEP should be authorized once we have reviewed the CEP and have identified expenditures that should be recorded in this subaccount. Until we have performed that review, however, it will be difficult and unnecessary to define the applicability of this account. We will not authorize this account at this time, but we are in no way prejudging the pending issues related to the unbundling of utility revenue cycle services(9) and the consideration of consumer education and protection measures.
This subaccount would record costs associated with the systems to bid and settle transactions made through the ISO and Power Exchange. At this time, establishment of a subaccount to recover costs associated with bidding systems costs, as described in the draft Advice Letters, would be premature. FERC's Phase II decision will address issues surrounding bidding systems standards and protocols. In addition, these costs are expected to be borne by generators in the marketplace, not by ratepayers.
This subaccount would record costs associated with installing metering and data collection systems at utility transmission substations and fossil, geothermal, and hydroelectric generating units, as required by the ISO and PX. Our view on establishing a subaccount to recover costs associated with additional metering costs is identical to the preceding discussion of bidding systems costs. It is premature to establish this subaccount pending FERC's Phase II decision.
The draft Advice Letters and PG&E's Preliminary Statement language for this subaccount are overbroad in defining the types of costs that can be recorded in this subaccount. PG&E, Edison, and SDG&E should include the following language regarding this subaccount in their compliance Advice Letters:
The Biennial Resource Plan Update Settlement Costs Subaccount records the costs associated with contracts approved by the Commission to settle issues associated with the Biennial Resource Plan Update (BRPU). Costs recorded in the BRPU Settlement Costs Subaccount shall be limited to costs of negotiations, buy-outs or other settlement costs approved by the Commission.
PG&E's draft Preliminary Statement language for this subaccount is complete and consistent with the intent of D.95-12-063. In their compliance filings, Edison and SDG&E should use PG&E's language.
The utilities seek to set up a subaccount to record for future recovery the costs of preparing, filing, and pursuing the rate reduction bond filings authorized in AB 1890. However, the utilities' current base rates include a component for legal and regulatory expenses that is a forecast of both planned and unplanned costs. As with other forecasted base rate elements, actual costs may turn out to be higher or lower than forecasted, and the possibility for loss or gain is part of the incentive to control costs that is built into both test year ratemaking and PBRs. We see no reason to treat the unexpected costs associated with the rate reduction bonds differently from other base rate items, and we will not authorize this subaccount.(10)
The language set forth by Edison and SDG&E in their draft Advice Letters is consistent with the intent of D.95-12-063.(11) PG&E, Edison, and SDG&E should use this language in their Advice Letter and Preliminary Statements filed in compliance with this decision.
This subaccount would record costs of developing contracts with third parties who, on behalf of PG&E, would develop and submit bids to the Power Exchange for power from PG&E's generation resources. At this time, establishment of a subaccount to recover costs associated with Bidding Company contract costs, as described in PG&E's draft Advice Letter, would be premature. This approach to mitigating market power has not yet been submitted to FERC, nor has it been acted upon by this Commission. In addition, FERC's Phase II decision will address the terms and conditions of the Power Exchange that are necessary to develop a Bidding Company contract. If this Bidding Company approach is approved by FERC in its Phase II decision, PG&E may submit an Advice Letter for this subaccount.
We will not authorize this subaccount. If the utilities face other restructuring- related costs in the future that they wish to record in a memorandum account, they should submit Advice Letters that describe the costs expected to be recorded and how they represent incremental costs to the utility.
The accounting procedures described by PG&E are appropriate and should be used by Edison and SDG&E in their compliance filings. In addition, the utilities are reminded that recording costs in a memorandum account does not ensure recovery of those costs but simply allows the utilities the opportunity to request recovery of these costs in a future Commission proceeding.
Utilities should file Advice Letters to establish an IRMA in compliance with this guidance within 10 days of the effective date of this decision. PG&E's draft Preliminary Statement includes the most detail of the three drafts. Edison and SDG&E should revise their Preliminary Statement language to correspond to PG&E's Purpose and Applicability sections. All utilities should revise the Purpose section to exclude utility labor and labor-related expenses, except as recorded in the Employee Transition Costs Subaccount. In addition, all utilities should include a level of detail in their compliance Advice Letter filing comparable to the detail of PG&E's draft. Advice Letters filed in compliance with this decision will be effective on the date filed.
In addition to its draft IRMA Advice Letter, PG&E submitted a draft Advice Letter and Preliminary Statement Language to establish a Competition Transition Charge Exemptions Memorandum Account (CTCEMA) to record costs associated with CTC exemptions set forth in AB 1890. Edison and SDG&E indicated their intent to file for such a memorandum account but they have not done so at this time.
PG&E has asked for the ability to record costs associated with CTC exemptions retroactive to December 20, 1995 because our Policy Decision requires customers who leave the utility's system on or after that date to pay CTC or an interim CTC (ICTC). We affirm this interpretation of our decision for the limited purpose of this memorandum account.
PG&E has not described how it would calculate "the amount of CTC costs that would have been recovered" but for the exemption, in order to make a debit entry into this memorandum account. PG&E should incorporate language into its Advice Letter and Preliminary Statement that describes how this calculation will be made consistent with the formula adopted in the ICTC decision (D.96-11-041), subject to revision in the transition cost proceeding. PG&E may submit this Advice Letter at any time, and if filed in compliance with this decision, it will be effective on the date filed.
Neither Edison nor SDG&E has been granted an ICTC, and therefore they have no interim formula by which to calculate embedded transition costs. Edison or SDG&E may submit Advice Letters to establish a CTC Exemptions Memorandum Account using a similar framework to that presented in PG&E's draft Advice Letter, tailored to each utility's specific situation regarding irrigation districts and AB 1890 requirements. The Advice Letters should contain a proposed formula for calculating the costs of CTC exemptions that will be subject to Commission review prior to approval.
Section 368(f) provides that a utility's cost recovery plan will include the flexibility to manage the renegotiation, buy-out, or buy-down of the utility's power purchase obligations. Exercise of this flexibility is subject to the Commission's review to assure that the revised arrangements provide net benefits to ratepayers and are reasonable in protecting the interests of both shareholders and ratepayers.
The utilities' plans include this flexibility. We will continue to review these renegotiations, buy-outs, and buy-downs to see that they meet the statutory standards.
Section 368(e) provides for a base revenue increase in 1997 and 1998 equal to inflation, as measured by the consumer price index, plus 2% (subject to the constraints of the rate freeze). The resulting funds are to be used only to enhance transmission and distribution system safety and reliability, and any funds not used for that purpose will be credited against future safety and reliability base revenue requirements. The base revenue increase is available to "an electrical corporation that is also a gas corporation serving more than four million California customers." PG&E has included a request for this increase in its plan.(12)
On October 8, 1996, prior to submission of its cost recovery plan, PG&E submitted AL 1612-E. AL 1612-E calculates the 1997 base revenue increase allowed under § 368(e) to be $164.383 million. On November 21, PG&E filed AL 1612-E-A to reduce its request to $164.231 million, due to changes in ERAM base revenues. PG&E did not describe how it would ensure that these revenues would be spent only to enhance transmission and distribution (T&D) system safety and reliability.
Both ORA and TURN protested AL 1612-E because the advice letter failed to explain how to ensure that expenditures of these additional revenues would not overlap with funds already authorized for T&D system safety and reliability in PG&E's last GRC. A failure to account for these expenditures could result in double recovery of these costs--once in GRC-authorized base rates, and again in the additional revenues provided in § 368(e). ORA recommends establishing a balancing account to track expenditures and recommends an annual reasonableness review on the use of these funds.
No party disputed PG&E's calculation of the base revenue increase, and PG&E's calculation is consistent with § 368(e). PG&E will be able to implement this base rate increase for 1997 without exceeding the rate levels in effect on June 10, 1996. The conditions in § 368(a) are requirements PG&E must continue to meet in conjunction with the incremental base rate increase authorized in § 368(e).
Because § 368(e)(2) placed specific restrictions on how this base revenue increase can be used, we agree with ORA that a balancing account should be established to track PG&E's expenditure of these funds. We also agree with TURN that these funds are not intended to supplant previously authorized funds for T&D system safety and reliability, but rather are designed to supplement funding previously authorized in the 1996 GRC. PG&E has not identified the accounting procedures it will use to demonstrate that it has spent these incremental funds in the manner required by the statute.
We will require PG&E to establish a one-way balancing account to ensure that any funds collected and not used are appropriately credited as required by § 368(e)(2). Attachment A sets forth the appropriate tariff language for addition to PG&E's Preliminary Statement. Within ten days of the effective date of this decision, PG&E should file a supplement to AL 1612-E-A to establish a one-way balancing account in compliance with Attachment A.
The high degree of specificity in Attachment A is required in order for the Commission to perform its future ratemaking duties and confirm through an audit procedure that the funds expended in this account are in fact incremental to the funds authorized for safety and reliability in the 1996 GRC decision (D.95-12-055). We will review or audit this account after the end of each year to determine how much of the incremental revenues was spent and to verify that expenditures recorded in the balancing account were incremental to the previously established base rates. PG&E may not fail to spend GRC-authorized amounts for these categories of expenses and related capital, while funding the work partially or wholly through the base rate increase of $164.2 million authorized today. Expenditures in this area will first be debited against the GRC- authorized amounts for an account or program; only after those amounts are exhausted will expenditures be counted against the base revenue increase funds.
In conjunction with its supplement to AL 1612-E-A, PG&E should submit a report that identifies the procedures it has developed to ensure that the funds provided by § 368(e) are truly incremental and are not used to pay for activities already funded in the 1996 GRC decision. This report should include a schedule for reconciling 1997 costs with the revenue increases. In addition, the Test Year 1999 GRC called for in § 368(e)(1) will be the appropriate forum for reviewing how any unspent incremental revenues will be credited against subsequent safety and reliability base revenue requirements, as required by § 368(e)(2).
PG&E had requested a similar rate increase in A.96-04-002. The status of that application will be addressed in a separate order.
Section 367(c)(1) appears to overrule for PG&E the provision in our Policy Decision that would limit the utilities' profits from running certain fossil-fueled plants (slip op. at 135). In that decision, we allowed utilities under certain conditions to retain up to 150 basis points above their authorized return on distribution rate base if the Power Exchange price exceeded the costs of running plants needed for reactive power/voltage control. Section 367(c)(1) requires the Commission to allow PG&E to retain any earnings from operation of plants needed for reactive power/ voltage support, and prohibits the Commission from requiring the utility to apply any portion of these earnings to offset transition costs.
Section 368(c) allows Edison(13) to "employ risk management tools, such as forward hedges, to manage the market price volatility associated with unexpected fluctuations in natural gas prices." Moreover, the statute allows Edison to collect as transition costs the out-of-pocket costs of acquiring these risk management tools, but not any losses resulting from changes in market prices.
Edison's plan echoes the statutory language without more detail, and to that extent we approve Edison's proposal. Depending on the nature of the particular risk management tool, exercise of this flexibility may require our further authorization under § 818 or § 851.
An exception to the rate freeze of § 368 is set forth in § 397(a), which allows SDG&E(14) to file a rate cap mechanism that includes a Fuel Price Index Mechanism (FPIM). The FPIM would allow "limited adjustments" to SDG&E's system average rate when gas prices are 10% higher or lower, calculated on a 12-month rolling average basis, than the price reflected in an index of gas prices as of January 1, 1996. SDG&E should request a rate cap mechanism consistent with § 397 by refiling the material previously presented in AL 998-E, with any modifications required by this decision. If the renewed advice letter is in compliance with the requirements of this decision, the rate cap mechanism will be effective on the date filed.
Section 368(b) requires the cost recovery plans to provide for the identification and separation of the overall individual rate components. The statute gives the examples of charges for energy, transmission, distribution, public benefit programs, and recovery of uneconomic costs, but other ways of dividing the total rate also are permitted.(15) On December 6, the utilities filed their proposals for rate unbundling. We will consider these proposals and implement the unbundling requirement in our proceeding on ratesetting issues.
The point of dividing the rate into components is to ensure that direct access customers pay the same charges for the services they receive from the utility, except for the energy component, as customers who continue to take bundled service from the utility.
The rate separation must not result in any cost shifting among customer classes, rate schedules, contracts, or tariff options, and contracts entered into before September 23, 1996 (the date AB 1890 took effect) and approved by FERC may not be affected by the rate separation. We will carry out these statutory requirements in our unbundling proceeding.
Therefore, IT IS ORDERED that:
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
ATTACHMENT A
Page 1
System Safety and Reliability Enhancement Funds Balancing Account (SSREFBA): PG&E shall maintain records to separately identify amounts funded under PG&E's Test Year 1996 General Rate Case and incremental expenditures incurred in planning and implementing transmission and distribution system safety and reliability enhancement activities, including, but not limited to, vegetation management and emergency response, funded by the base revenue increase provided in Public Utilities Code § 368(e). This account is to record:
(1) incremental transmission expenditures under account numbers 560.0, 561.0, 562.0, 563.0, 564.0, 565.0, 566.0, 567.0 (operations) 568.00, 569.00, 570.00, 571.00, 571.62, 571.63, 571.64 571.65, 571.66, 571.67, 571.68, 571.69, 571.70, 571.71, 571.72, 571.73, 571.74, 571.75, 572.00, 573.00 (maintenance);
(2) incremental distribution expenditures in account numbers 580.0, 582.0, 583.2, 583.3, 584.0, 585.0, 586.0, 587.7, 587.8, 587.9, 588.0, 588.6, 589.0 (operations), 590.00, 591.00, 592.00, 593.62, 593.63, 593.64, 593.65, 593.66, 593.67, 593.68, 593.69, 593.70, 593.71, 593.72, 593.73, 593.74, 593.75, 594.00, 595.00, 593.00, 596.00, 597.00, 598.00 (maintenance);
(3) incremental capital-related costs (i.e., return, taxes, depreciation) associated with incremental capital expenditures for the major work categories used in PG&E's 1996 General Rate Case ("program numbers") for "repair/replace failed/damaged electric facilities (distribution)" (#303), "provide normal capability - electric distribution" (#307), "electric service reliability - install new plant" (#309A), "electric service reliability - replace obsolete/deteriorated facilities" (#309B), "electric service reliability - provide emergency capability" (#309C), "electric service reliability - underground cable replacement program" (#309D), "repair/replace failed/damaged electric facilities
ATTACHMENT A
Page 2
(transmission)" (#373), "electric service reliability - install new plant (transmission)" (#379A), "electric service reliability -
repair/replace damaged facilities (transmission)" (#379B), "fleet, equipment, and tools" (#902), and "telecommunications system" (#904).
PG&E shall make the following entries to SSREFBA at the end of each month:
a. A debit equal to the expenses in (1) and (2) above and incremental capital-related costs listed in (3) above incurred for System Safety and Reliability Enhancement activities during the month;
b. A credit equal to the annual revenues authorized for System Safety and Reliability Enhancement activities times the applicable monthly allocation factor shown in Preliminary Statement, Part D. item 6.a.;
c. A debit or credit, as appropriate, reflecting interest on the average balance during the month at a rate equal to one-twelfth the interest rate on Commercial Paper for the previous month, as reported in the Federal Reserve Statistical Release G.13, or its successor.
The Commission has authorized $164.231 million for 1997 for System Safety and Reliability Enhancement activities. To the extent these revenues are not expended for enhanced system safety and reliability, they shall be carried over and credited against subsequent safety and reliability base revenue requirements. PG&E's 1999 GRC is the appropriate forum for reviewing how excess revenues are credited against subsequent safety and reliability base revenue requirements. Excess revenues shall not be used to pay monetary sanctions imposed by the Commission.
(END OF ATTACHMENT A)
(1) All section references are to the Public Utilities Code.
(2)"Small commercial customer" is defined as a customer with a maximum peak demand of less than 20 kilowatts (§ 331(h)).
(3)Section 330(a) states the Legislature's expectation that the implementation of the bill will lead to a cumulative rate reduction for residential and small commercial customers of at least 20% by April 1, 2002.
(4) D.96-08-025 imposed similar constraints on Edison's real-time pricing schedules, but those schedules are not the subject of AL 1196-E.
(5)The annual limits we established in D.96-04-059 on recovery of the costs of SONGS nuclear generation units, which we suggested should be applied to all other nuclear generation units, were eliminated by § 368(d) to allow greater opportunity for recovery during the recovery period.
(6)The conventional cost of capital filing has been eliminated for SDG&E in D.96-06-055 and for Edison in D.96-09-092. The cost of capital for these utilities will be adjusted in relation to a market index of bond prices.
(7) We addressed the refund function in D.96-12-025, when we ordered the creation of the Electric Deferred Refund Account. Shared revenues arise from a variety of sources, e.g., leases of utility facilities, that create a source of other operating revenue not forecasted in the GRC or from the rewards or penalties associated with PBR mechanisms.
(8) We have eliminated the ERAM for Edison's nongeneration base revenue requirement, except as needed to adjust for the effect of DSM. (D.96-09-092.) We do not consider today whether or not it is desirable or appropriate to apply some form of ERAM solely to the distribution revenue requirement. Parties may address this general issue in our rate setting proceeding. The details of implementing a distribution ERAM may also be considered in the distribution PBR proceedings.
(9) 9 Utility revenue cycle services include metering, billing, customer services and uncollectibles.
(10) Section 840(c) requires the Commission's financing order authorizing rate reduction bonds to include a procedure to ensure recovery of the costs of issuing, servicing, and retiring the rate reduction bonds. We do not today prejudge any request in the rate reduction bond applications for recovery of the costs identified in the statute.
(11) 11 The language should be updated to reflect the change of the Commission Advisory and Compliance Division to the Energy Division.
(12)Applying this subsection requires some interpretation. Placement of the phrase "serving more than four million California customers" in this subsection appears to modify "gas corporation," but that would render this provision meaningless, since no current electric corporation also serves 4 million gas customers. If the intent was to refer to combined electric and gas utilities with more than 4 million customers, then it would appear that Edison, which serves some gas customers on Santa Catalina Island, could also qualify for this increase. However, the Legislature was careful to describe Edison in different terms in, e.g., §368(c). We note that a description similar to the one in § 368(e) appears in § 367(c)(1), and the latter description more clearly fits PG&E's characteristics. We are thus faced with an interpretive choice of either finding that the Legislature intended § 368(e) to refer to both PG&E and Edison or concluding that the Legislature inadvertently failed to revise the description in § 368(e) to be as unambiguous as the similar description in § 367. We conclude, subject to clarification or correction by the Legislature, that the latter interpretation makes the most sense under the circumstances surrounding the enactment of this legislation.
(13)The statute grants this flexibility to "an electrical corporation that, as of December 20, 1995, served more than four million customers, and that was also a gas corporation that served less than four thousand customers." Although Edison is usually thought of as an electric utility only, it qualifies for this provision by virtue of its natural gas service on Santa Catalina Island. No other utility fits this description.
(14)Section 397(a) refers to "an electrical corporation which is also a gas corporation and served fewer than four million customers as of December 20, 1995." Only SDG&E fits this description.
(15)The costs of decommissioning nuclear power plants must be separately identified and recovered as a nonbypassable charge (§ 379), and a nonbypassable public goods charge is required by § 381.