| Application No: | 96-12- |
| Exhibit No: | SCE-1 |
| Witnesses: | Various |
| PREPARED TESTIMONY |
Before the
Public Utilities Commission of the State of California
| Rosemead, California | |
| December 1996 |
Figure V-1 Retail Meter Reading System Information Flow Sample Calculation Of Hourly Usage For 30th Day Of April 34Figure V-2 Settlement Timeline 35Figure V-3 Example Of Imbalance Measurement 40 Table IV-1 Development Of The Nongeneration Revenue Requirement StartingPoint 18Table IV-2 Illustrative FERC Jurisdictional Transmission RevenueRequirement 20Table IV-3 January 1, 1998 Public Benefit Revenue Requirement (ExcludingCurrent Care Surcharge Amounts) 26
INTRODUCTION
In his Assigned Commissioner's Ruling dated June 21, 1996 (June 21 ACR), Commissioner Duque specified that this application "should include implementation level detail in three areas":
The June 21 ACR also required that this application "reflect any resolution at FERC [the Federal Energy Regulatory Commission] regarding the T&D [transmission and distribution] separation." In addition, the recently enacted restructuring legislation, Assembly Bill (AB) 1890, requires unbundling of charges for the recovery of costs of Public Benefit programs and nuclear decommissioning.
On October 25, 1996, the Commission issued its "Opinion Ordering the Separation of Transmission From Distribution Costs and Requesting Comment on Related Items" (Ratesetting Decision)./ The Ratesetting Decision confirmed the scope of this application in Ordering Paragraph No. 1:
By November 15, PG&E, SCE and SDG&E should file their total ratebase and base rate revenue requirement based on our last authorization and should separate this total between transmission and distribution, consistent with FERC orders.
Subsequent to Edison's last rate authorization, Edison proposed a change to its cost separation methodology in its Generation PerformanceBased Ratemaking (PBR) Application as discussed in Chapter III of this exhibit. In addition, on October 30, 1996, FERC issued its decision approving, with minor modifications, Edison's proposed jurisdictional split between transmission and distribution facilities./ Both of these proposed changes will, if adopted, modify Edison's last rate authorization. Edison has based its calculations for this Application on the assumption that the Commission will adopt both of the foregoing proposals. Accordingly, pursuant to the June 21 ACR and the Ratesetting Decision, Edison files this application for functional unbundling of rates for electric service to be rendered on and after January 1, 1998.
Chapter II discusses the major policy principles upon which this filing is based. Among these principles are the rate freeze mandated by AB 1890, residual determination of Competition Transition Charge (CTC) for all customers including those on special contracts and tariff options, and a rate credit approach to the derivation of a distribution PBR rate from Edison's nongeneration PBR rates on January 1, 1998.
Chapter III incorporates the testimony included in Exhibit SCE5 of Edison's Generation PBR application, filed July 15, 1996. That application contained extensive testimony explaining Edison's methodology for attributing costs between Edison's generation and nongeneration functions. Chapter III of this filing explains why that exhibit is being litigated in the Generation PBR proceeding and, based on Edison's proposed schedule, is to conclude prior to January 1, 1998. Edison includes that testimony in this application and proposes to litigate it in this proceeding only if the Generation PBR procedural schedule does not allow a Commission decision before January 1, 1998.
Chapter IV presents an overview of the existing cost recovery procedures and the cost recovery procedures that will be in place on January 1, 1998 in conformance with the Restructuring Policy Decision/ and AB 1890. In addition, this chapter includes forecast 1998 revenue requirements and associated ratemaking for (1) distribution, (2) transmission, (3) Public Benefit programs, and (4) nuclear decommissioning. Due to the residual determination of the generation rate as a result of the rate freeze mandated by AB 1890, there is no longer a need to forecast generation or CTCrelated revenue requirements. This application does not address cost recovery authorized by California Public Utilities (PU) Code Section 376 relating to costs of programs to accommodate the implementation of direct access. Such cost recovery will be the subject of subsequent applications or filings, in accordance with the terms of AB 1890.
Chapter V describes how Edison will unbundle its rates into separate charges for energy, transmission, distribution, CTC, Public Benefit programs, and nuclear decommissioning beginning January 1, 1998. In addition, in that chapter Edison fully describes its rate credit approach to developing a starting point for its distribution rate PBR in 1998 based on nongeneration PBR rates in effect for 1997. Appendix B contains illustrative unbundled rates for January 1, 1998 for all of Edison's retail rate schedules. Development of final 1998 rates and tariffs must await several critical path steps, including (1) FERC's authorization of Edison's 1998 transmission revenue requirement and decisions regarding responsibility for retail transmission rate design; and (2) the Commission's decision on the cost separation included in Edison's Generation PBR filing. Edison plans to submit its final 1998 rates by Advice Filing in late 1997 during the implementation phase of this proceeding.
Chapter VI presents Edison's proposals for establishing new
regulatory proceedings to replace current proceedings that are
no longer necessary. These proposals cover the period of the
rate freeze mandated by AB 1890, which eliminates the need
for most proceedings currently established to forecast various
components of Edison's revenue requirement.
In this chapter, Edison discusses the policy principles upon which its proposed functional rate unbundling is based. Among these principles are (i) the rate freeze mandated by AB 1890, (ii) residual determination of CTC for all customers, (iii) the inclusion of all Power Exchange (PX) charges in the cost of energy, (iv) excluding the use of load profiles for customers with hourly meters, (v) provision of 10% rate reduction for residential and small commercial customers contingent on the issuance of Rate Reduction Bonds, and (vi) a rate credit approach to the calculation of the distribution PBR rates on January 1, 1998. Each one of these principles is supported by the PU Code and is consistent with sound ratemaking practices that prevent costshifting while allowing Edison to recover from customers only those costs authorized by the Commission.
Section 368(a) of the PU Code requires that the utilities' "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." This rate freeze is to remain in effect until the earlier of December 31, 2001/ or the date on which the Commission authorized costs for Edison's generationrelated assets have been recovered. Therefore, through the rate freeze period, the total rates charged to the bundled service customers will remain at the same level although residential and small commercial customers will receive a 10% bill credit. As described below, the rates to the direct access customers would change over the rate freeze period only to the extent their cost of procuring energy from third party providers differs from the Utility Distribution Company's (UDC's) cost of procuring energy from the PX.
PU Code Section 367(e)(1) provides that transition costs shall "be allocated among the various classes of customers, rate schedules, contract rates, and tariff options including selfgeneration deferral, interruptible and standby rate options in substantially the same proportion as similar costs are recovered as of June 10, 1996." Section 368(b) further states that unbundling of rates and identification of individual rate components such as CTC should result in "no cost shifting among customer classes, rate schedules, contract[s], or tariff options." The most straightforward method of implementing this legislative direction, while adhering to the rate freeze mandated by AB 1890, is the residual determination of CTC. To the extent other rates such as transmission and distribution rates rise, the component of the total frozen rate allocated to the recovery of transition costs would decline, increasing the risk to the utility of not recovering such costs during the rate freeze period and shielding customers from any overall increase in their rates.
To ensure that costs are not shifted between direct access and bundled UDC customers, and to ensure that direct access customers pay the same unbundled component charges, other than energy, a bundled service customer pays,/ it is necessary to extend the principle of residual determination of CTC to individual direct access customers. In order to implement this policy, the credit provided to the direct access customers for procuring their own energy should be equal to the UDC's cost of procuring energy for such customers from the PX. This method ensures that, consistent with AB 1890, these customers incur increases (decreases) in the total price they pay for electricity only to the extent the price for the energy charged by their supplier exceeds (is below) the PX price./
The Commission's policy decisions and AB 1890 require that rates for UDC customers include the cost of purchasing power from the PX and that direct access customers pay the same rates as UDC customers except for the cost of energy from the PX. Therefore, determination of this cost is important to all customer classes.
While this appears to be a simple task, it is in fact quite complicated. Edison will be purchasing energy from the PX on a dayahead and an hourahead basis. Later, there will be expost settlements to determine what was actually purchased and at what spot price. This determination is further complicated by the fact that allowing direct access based on load profiles will require a full meter reading cycle to be completed before the PX can precisely determine the amount of energy used. Edison anticipates that it will receive billing settlements from the PX as much as 50 days beyond the date of actual consumption and that a given day's energy use will be settled more than once during this period.
Edison proposes to calculate the hourly cost of energy from the PX for a particular hour as the weighted average of the dayahead and hourahead prices for that hour, adjusted to reflect prior expost settlements. This will prevent costly, confusing, and continuous rebilling of customers' energy usage as settlements are received from the PX. This methodology is fully described in Chapter V.
Edison proposes to calculate CTC residually based on the actual hourly usage of the customer, whether bundled or direct access. As discussed in Section C of this chapter, the hourly CTC will be calculated by subtracting the hourly PX energy cost from the otherwise applicable generation rate for that hour. This methodology will be applied to customers with realtime meters regardless of whether they belong to a rate class whose other members without realtime meters utilize load profiles for CTC determination.
Calculating the CTC in this manner will allow customers who are on a TOU tariff or who are eligible for a TOU tariff the opportunity to capture the benefit of shifting usage from one time of use period to another. It will also maintain equitable standards for both UDC and direct access customers and will prevent gaming of load profiles. If the CTC were to continue to be calculated based on the class load profile after a customer had a realtime meter, the CTC would not change if a customer were to modify its actual usage pattern once it had selected direct access. This creates an incentive for customers to select direct access, not because they could procure lower cost energy, but because they expect their load profile to be better than the class average. This is not consistent with competitive neutrality of CTC. Calculating the CTC based on actual usage of all customers who have a realtime meter, whether they have selected direct access or not, will provide a level playing field on which suppliers can compete based on their cost of providing energy.
Section 1(e) of AB 1890 requires a rate reduction for residential and small commercial customers of not less than 10 percent starting on January 1, 1998 contingent upon the issuance of financing orders by the Commission and Rate Reduction Bonds from the California Infrastructure and Economic Development Bank. The amount of Rate Reduction Bonds issued must be sufficient to achieve the mandated 10 percent rate reduction to these customers. The linkage between this rate reduction and the issuance of the bonds is made even more explicit in PU Code Section 330(w):
It is the intent of the legislature to require and enable electrical corporations to monetize a portion of the competition transition charge for residential and small commercial customers so that these customers will receive rate reductions of no less than 10 percent for 1998 continuing through 2002. Electrical corporations shall, by June 1, 1997, or earlier secure the means to finance the competition transition charge by applying concurrently for financing orders from the Public Utilities Commission and for rate reduction bonds from the California Infrastructure and Economic Development Bank.
Due to the fact that the actual financing costs for the Rate Reduction Bonds will not be known until the utilities' financing applications are approved by the Commission, the present filing only describes the conceptual method for the development of a surcharge for the residential and small commercial customers to repay the costs of such bonds. The actual surcharge will be developed after the Commission approves Edison's financing applications.
In D.96-09-092, the Commission adopted a nongeneration PBR mechanism for Edison. To implement its nongeneration PBR rates, Edison filed Advice Letter 1191E which is currently awaiting Commission approval. In this application, Edison proposes to use a rate credit approach to unbundle its nongeneration PBR rates into separate transmission and distribution rates. According to this method, the appropriate portion of the FERC/Commissionadopted transmission rates will be subtracted from the Commissionadopted nongeneration PBR rates on the same date to calculate the starting point for distributiononly PBR rates. This separation will be performed only once, on January 1, 1998. However, prior to January 1, 1998, Edison's nongeneration PBR will need to be updated to accommodate the Commission's decision in Edison's revised cost separation proposal. Following this separation, these distribution rate levels will be updated using the CPIX update rule in subsequent years independent of the FERC/Commissionadopted changes in transmission rates. The transmission rates will be updated when FERC/Commission approve changes in their levels or structures.
This approach to the development of a distribution PBR rate is appropriate as it eliminates the need for litigation of a new distribution PBR while ensuring that no more and no less than the nongeneration PBR rates adopted by the Commission are charged to customers. The costs reflected in the nongeneration PBR rates are those authorized for recovery by the Commission and the fact that about 10% of such costs are also litigated at FERC/ should not result in relitigation of a distribution PBR by this Commission. This will ensure that customers pay no more than and Edison receives no less than the amount adopted by the Commission for its nongeneration functions. In addition, all stakeholders will benefit from this approach by eliminating any contentious and lengthy litigation of a new distribution PBR.
It is expected that the FERCapproved transmission revenue
requirement will include costs for functions related to direct
access such as transmission upgrades to reduce "mustrun"
requirements and Independent System Operator (ISO) uplift charges/
that were not anticipated in the nongeneration PBR. Edison proposes
to adjust the FERCapproved revenue requirement by subtracting
the costs of these items from that FERC revenue requirement prior
to determining the distribution PBR starting point. These costs
will, however, be included in the transmission rate that is established
on January 1, 1998. This will cause a reduction in the CTC
level which is determined residually. Since some of these functions
are direct accessrelated, Edison will ask for recovery of
an appropriate amount/ of CTC
beyond the rate freeze period consistent with PU Code Section 376
should it not be able to fully recover its transition costs during
that period.
In its July 15, 1996 Generation PBR application, Edison filed extensive testimony explaining its methodology for attributing costs between Edison's generation and nongeneration functions. This testimony is included in Exhibit SCE5 of Edison's application, which is currently being litigated. Edison has proposed that the Generation PBR proceeding conclude prior to January 1, 1998.
In addition, Edison recommended in Revisions to ACRA/RCRA Procedures Testimony, included in Exhibit SCE6 of Edison's application, that the portion of Reduced Cost Recovery Amount (RCRA) currently reflected for transmission be transferred to distribution to be consistent with the development of Edison's transmission revenue requirement at FERC.
In the event Edison's Generation PBR proceeding is delayed such
that it becomes clear that a decision may not be issued before
January 1, 1998, Edison will propose that the Cost Separation
Testimony and the Revisions to ACRA/RCRA Procedures Testimony
be addressed in this or another appropriate proceeding so that
it may be decided before January 1, 1998. In order to plan
for that contingency, Edison attaches to this testimony a copy
of the Cost Separation Testimony as Appendix C and
a copy of the Revisions to ACRA/RCRA Procedures Testimony
as Appendix D and incorporates that testimony herein.
This chapter first presents an overview of existing cost recovery procedures and then the cost recovery procedures that Edison proposes to establish as of January 1, 1998 in conformance with the Restructuring Policy Decision and AB 1890. In addition, this chapter includes forecast 1998 revenue requirements and a description of the associated ratemaking for: (1) distribution, (2) transmission, (3) Public Benefit programs, and (4) nuclear decommissioning. Due to the residual determination of the generation rate as a result of the rate freeze mandated by AB 1890, there is no longer a need to forecast generation or CTCrelated revenue requirements.
In general, costs are currently recovered through the procedures used by utilities prior to restructuring, such as the General Rate Case (GRC), operational and financial attrition filings, and balancing account procedures. These procedures can essentially be separated into two components, base rates and offset clause recovery procedures.
The Commission establishes base rates based on forecast costs to recover nonfuel operation and maintenance (O&M) expenses and investment-related costs, including depreciation, decommissioning, taxes, and a reasonable return on authorized rate base. Edison then recovers these forecast costs as base rate revenues authorized by the Commission for the applicable year. The Authorized Level of Base Rate Revenues (ALBRR) establishes the amount of base rate revenues to be recovered through the Electric Revenue Adjustment Mechanism (ERAM). The general purpose of ERAM is to reflect in rates any difference between the recorded level of base rate revenue and the ALBRR./
Offset clauses were established by the Commission to recover specified costs, generally on a "dollar-for-dollar" basis. Edison's major offset clause is the Energy Cost Adjustment Clause (ECAC) which recovers most of Edison's fuel, fuelrelated and purchased power costs. The Company files an ECAC application annually to set the ECAC billing factors to recover forecast expenses. Any difference between the revenue generated by the ECAC billing factors and the recorded ECACincludable expenses is accumulated in the ECAC balancing account and then collected from or returned to customers in the following year. In addition, the Company must make a showing as to the reasonableness of its prior year's operations and the costs incurred. Any costs found by the Commission to have been unreasonably incurred are disallowed recovery.
As part of Edison's 1995 GRC, a new revenue requirement authorization procedure was adopted for the San Onofre Nuclear Generating Station (SONGS) Units 2&3 sunk costs to achieve full recovery by December 31, 2003 at a reduced rate of return./ The revenue requirement associated with SONGS 2&3 sunk costs is currently recovered through base rates. Edison will have the opportunity to recover its share of incremental costs (O&M, portions of A&G, nuclear fuel, incremental capital additions and property taxes) through an Incremental Cost Incentive Pricing (ICIP) mechanism via a fixed amount per kWh generated (about 4 cents per kWh on average). The revenue requirement determined pursuant to the SONGS 2&3 ICIP mechanism is currently recovered through Energy Cost Adjustment Billing Factors (ECABFs). Pursuant to the Restructuring Decision, Edison has proposed similar ratemaking treatment for its share of the Palo Verde nuclear generating stations Units 1, 2, & 3 to be effective January 1, 1997 (Application No. 96-02-056)./
Edison's nuclear decommissioning obligation and other reasonable, unavoidable costs not included in the ICIP mechanism are currently recovered through base rates at levels authorized in Edison's 1995 GRC. Edison's SONGS Unit 1 shutdown O&M costs are also currently recovered through base rates at levels authorized in the 1995 GRC. Certain nuclear fuel-related expenses, such as Department of Energy Decommissioning and Decontamination (DOE D&D) fees, are currently recovered through ECABFs.
Consistent with the Restructuring Policy Decision and AB 1890, Edison's cost recovery effective January 1, 1998 will be from the following sources: (1) market revenues; (2) PBR mechanisms and other incentive based mechanisms; (3) charges for transition costs; (4) charges for Public Benefit programs; (5) the transmission revenue requirement adopted by FERC for FERC jurisdictional services; (6) a nuclear decommissioning charge; (7) a miscellaneous pass-through balancing account mechanism to recover PBR exclusions and one-time amortization amounts (nonPBR component of distribution); and (8) a rate reduction repayment charge (for residential and small commercial customers only). As discussed in Chapter VI of this exhibit, these procedures will completely replace the current GRC, attrition, and ECAC proceedings.
As discussed in greater detail elsewhere in this exhibit, pursuant to AB 1890, rates are frozen for all customers at the adopted June 10, 1996 levels. In addition, Edison will reduce residential and small commercial customer rates not less than 10% for 1998 through March 31, 2002 subject to the issuance of Rate Reduction Bonds. (See Chapter V of this exhibit.) Edison will subtract the adopted distribution rates,/ transmission rates, Public Benefit charges, nuclear decommissioning charge, and rate reduction repayment charges (for residential and small commercial customers only) from the rate levels in effect as of June 10, 1996 to determine the generation rate; i.e., it will set the generation rate residually. CTC will further be residually determined by subtracting Edison's cost of procuring energy and other services from the PX from this generation rate.
Edison's proposed functional rate unbundling will ensure that revenues can be appropriately tracked. Revenues collected through generation rates will first be used to pay the PX for Edison's purchases from the PX, with the remainder recorded in the Transition Cost Balancing Account to be available for transition cost recovery./ Revenues collected through the PBRrelated distribution rates will be tracked for use in the distribution PBR revenue sharing mechanism. Revenues collected through the nonPBR component of distribution rates will be tracked to ensure funding of such Commissionauthorized programs as Hazardous Waste CleanUp and LowEmission Vehicles. Revenues collected through transmission rates will recover Edison's transmission costs. Revenues collected through the nuclear decommissioning charge will be separately tracked in a balancing account and will only be used for nuclear decommissioning cost recovery. Similarly, revenues collected through the Public Benefit charges will be tracked in a balancing account and will be available only to fund Edison's energy efficiency, RD&D, renewables, and lowincome programs. Some portion of the revenues from this latter source will be provided to the California Energy Commission (CEC) or another designated agency that will be in charge of administering renewable, public interest, RD&D and possibly other programs.
Given the ratesetting methodology described above and in more detail in Chapter V i.e., the residual determination of the generation rate 1998 forecast revenue requirements are necessary only for the determination of: (1) distribution rates, (including a PBR and a non-PBR component); (2) transmission rates; (3) Public Benefit charges; and (4) the nuclear decommissioning charge. The remainder of this section presents forecast 1998 revenue requirements for these components and the corresponding proposed ratemaking treatment for each component.
The Commission approved Edison's nongeneration PBR in Decision No. 9609022 to be effective on January 1, 1997. As described in Chapter V of this exhibit, Edison proposes a rate credit approach for determining the starting point for the distribution PBR in 1998. Under this approach, the appropriate portion of the 1998 transmission revenue requirement established by FERC, which is currently included in Edison's nongeneration PBR, will be converted into transmission rates and subtracted from the nongeneration PBR rates, leaving a distribution PBR rate./ This distribution PBR rate will then be escalated based on inflation less a productivity factor (i.e., CPIX) for the years 1999, 2000, and 2001. The distribution PBR will be reviewed by the Commission and may be extended or revised after 2001.
Prior to January 1, 1998, however, Edison's nongeneration PBR will need to be updated to accommodate the Commission's decision on Edison's revised cost separation proposal. Edison originally filed a cost separation methodology in connection with its application for the nongeneration PBR in Application No. 9312029 on December 23, 1993 (the "Phase I cost separation"). The Office of Ratepayer Advocates (ORA) objected to this cost separation methodology and proposed that Edison engage in a more detailed methodology. Edison provided a more detailed cost separation methodology in Exhibit SCE5 of its Generation PBR Application No. 9607009 (the "Phase II cost separation"). Exhibit SCE5 reflects a detailed cost separation methodology that identifies and attributes Edison's costs as directly as possible to the appropriate segment as discussed in Chapter III of this exhibit.
On September 20, 1996 the Commission adopted a nongeneration PBR mechanism for Edison effective January 1, 1997/ based on Edison's Phase I cost separation. Since Edison's Phase II Cost Separation methodology was completed later and presented in the Generation PBR proceeding, the Commission did not have the opportunity to consider it in deciding Edison's nongeneration PBR.
Thus, Edison presently has an approved cost separation methodology that will become effective on January 1, 1997 (Phase I) and is presently litigating a cost separation methodology (Phase II) that, if approved, will become effective on January 1, 1998.
The following table identifies the nongeneration PBR starting
point based on the Phase II cost separation methodology contained
in Exhibit SCE5 in Edison's Generation PBR filing which
is appended to this volume. After adjusting for the transfer
of some facilities previously classified by Edison as transmissionrelated
to generationrelated, pursuant to the October 30, 1996
FERC ruling, and adjusting for Revenue Credits, DemandSide
Management (DSM), Research, Development and Demonstration (RD&D),
and Edison Pipeline and Terminal Company (EPTC),/
the proposed starting point for nongeneration PBR base revenue
requirement is $2,027,881,000. As discussed in Chapter V,
Edison proposes to utilize this revenue requirement to redesign
its nongeneration PBR rates based on the same methodology used
in designing these rates in Advice Letter 1191E to
recover the nongeneration revenue requirement derived from the
Phase I cost separation. Next, these rate levels are adjusted
by CPIX for 1997 and 1998 and are utilized to design the
starting point for the distributiononly rate PBR in 1998
after subtracting the transmission rates designed based on the
transmission component of this revenue requirement.
Development Of The Nongeneration Revenue Requirement Starting Point / | ||
| Gen PBR A. 96-07-009 (Exhibit SCE-5, Tables V-8, V-9) | ||
| Nongeneration PBR Starting Point | 2,237,425 | |
| Adjust for: | ||
| Incremental Generation-Related Transmission Change * | (8,217) | |
| Revenue Credits ** | (131,334) | |
| DSM ** | (70,076) | |
| RD&D ** | (19,880) | |
| Edison Pipeline & Terminal Company (EPTC) ** / | 19,963 | |
| Net Nongeneration Starting Point / | 2,027,881 | |
| * Additional generation-related transmission costs over amounts included in SCE5 as a result of FERC decision of 10/30/96.
** Includes franchise fees and uncollectible expense. | ||
In D.96-10-074, the Commission directed Edison to file on November 15, 1996 a separation of its rate base and revenue requirement into generation, transmission, and distribution components, reflecting the October 30, 1996 FERC decision in Docket EL9648 on the identification of FERC jurisdictional facilities.
In general, Edison is basing its separation of generation and nongeneration costs on the proposal presented in its July 15, 1996 Generation PBR (Phase II) filing. That proposal has been revised as required by D.9610074 to reflect the October 30, 1996 FERC decision regarding transmission facilities. The FERC decision ordered Edison to exclude from transmission the SONGS generationrelated transmission facilities and the twelve generationtie lines which FERC viewed as radial.
The development of the transmission revenue requirement at FERC is similar to the development of a CPUC general rate case filing. Operation and maintenance costs, capital additions and retirements, as well as common cost assignments for administrative and general expenses and general plant must be estimated. Edison is in the process of developing the WEPEX Phase II filing to submit to FERC, currently scheduled for March 1997. As a result, Edison will not have an approved transmission revenue requirement from FERC until 1997, and possibly later. Nevertheless, Edison has, for illustrative purposes, estimated its transmission revenue requirement for purposes of this application. The methodology used in deriving this estimate is discussed below. Once FERC approval is obtained, Edison will, as part of an implementation Advice Letter, reflect the resulting transmission and distribution rates.
Given the absence of a FERCadopted transmission revenue requirement for 1998, Edison is providing, for illustrative purposes, a transmission revenue requirement based on its Open Access Transmission (OAT) rate filing made before FERC in Docket No. OA9676000 on July 9, 1996. That OAT revenue requirement is based on a FERC carrying charge formula applied to Edison's 1995 recorded transmission data. In addition, for purposes of this filing, certain minor adjustments were made to the OAT revenue requirement to comport with traditional ratemaking practices. This calculation is shown below in Table IV-2.
The OAT transmission revenue requirement is based on Edison's
traditional definition of transmission, and therefore includes
generationrelated transmission facilities and local distribution
facilities which, pursuant to FERC's October 30, 1996 decision,
will not be included in Edison's FERC transmission revenue requirement.
Consistent with that decision, Edison estimates that the FERC
jurisdictional transmission facilities represent approximately
57% of Edison's traditionally defined total transmission facilities.
Therefore, the FERC transmission revenue requirement is developed
by multiplying the adjusted OAT revenue requirement by 57%.
Illustrative FERC Jurisdictional Transmission Revenue Requirement | ||
| Open Access Transmission Revenue Requirement | 442,409 | |
| Account 565 Expenses | 8,091 | |
| Wheeling Revenues from existing Trans. Contracts | (32,724) | |
| Adjusted Transmission Revenue Requirement | 417,776 | |
| FERC Jurisdictional Transmission Facilities % | 57% | |
| FERC Jurisdictional Transmission Revenue Requirement | $238,132 | |
| CPUC Jurisdictional Allocation Factor | 0.9975 | |
| CPUC Transmission Revenue Requirement | $237,537 | |
It is possible that FERC will accept in 1997 the proposed transmission revenue requirement to be effective on January 1, 1998, on an interim basis, subject to refund. If FERC renders an interim decision for rates effective January 1, 1998 and a final decision sometime thereafter, a mechanism such as a tracking account must be implemented at the CPUC to adjust the transmission and distribution rates at that time to reflect the final FERC decision.
Edison is proposing two separate components of the distribution rates a PBR component and a non-PBR component. This is necessary to ensure proper revenue accounting for the operation of the PBR net revenue sharing mechanism, distinct from miscellaneous PBR exclusions and pass-though items that also will be collected through distribution rates.
As discussed in this exhibit, a rate credit approach will be utilized in the determination of 1998 PBR distribution charges. The appropriate portion of transmission revenue requirement for 1998 will be converted into transmission rates and subtracted from nongeneration PBR rates resulting in the 1998 PBR component of distribution rates. This PBR component of distribution rates would then be escalated at CPI-X beginning on January 1, 1999, and each January 1 thereafter through the year 2001.
Edison is proposing to eliminate the current ECAC and ERAM balancing accounts as of January 1, 1998./ Costs currently recovered through the ECAC and ERAM mechanisms in 1997 will generally be replaced with recovery through the market or CTC. However, some items will remain after January 1, 1998 that are not subject to either market or CTC recovery and have either been adopted as exclusions to the nongeneration PBR mechanism, or are appropriate for pass-through balancing account ratemaking beginning in 1998.
Effective January 1, 1998, Edison proposes the establishment of the Miscellaneous Adjustment Mechanism (MAM) balancing account which will include items currently recovered through the ECAC billing factor such as:
items currently reflected in base rates such as:
items currently recovered through the ERAM billing factor such as:
In addition, as described in Chapter V, the ISO/PX structure will require an adjustment to reflect actual energy losses (including errors in line losses, load profile errors, and energy theft) incurred during operation of the electrical system as compared to the estimated losses and load profiles used by the ISO/PX to calculate hourly delivery of energy to the UDC and other market participants./ These losses are currently recovered in ECAC and are proposed to be recovered through the MAM beginning January 1, 1998.
Appendix A to this exhibit lists the items (including descriptions, authorities, and forecast 1998 amounts) which are proposed to be recovered through the MAM. This listing is not intended to be comprehensive; for example, any ratepayer refunds that may be ordered in Commission decisions on outstanding ECAC Reasonableness proceedings could be returned to customers through the MAM. The forecast 1998 MAM revenue requirement is based on what is known at this time and is a negative $22.244 million. The MAM revenue requirement will be collected in the MAM Billing Factor (MAMBF).
The MAM balancing account will track, on a monthly basis, the authorized or recorded revenue requirements/ compared to recorded MAMBF revenues. Accumulated balances in the MAM will accrue interest based on the monthly 3month commercial paper rate.
The MAM will ensure that no more and no less than Edison's authorized miscellaneous revenue requirements are ultimately collected from customers. This will be accomplished through an annual "true-up" process where year-end under- or over-collections in the MAM balancing account will be added to the next year's forecast of MAM revenue requirement.
AB 1890 mandates the establishment of a separate nonbypassable rate component to collect the revenues used to fund the following Public Benefit programs: (1) cost-effective energy efficiency and conservation activities; (2) research and development not adequately provided by competitive and regulated markets; (3) instate operation and development of existing and new and emerging renewable resource technologies;/ (4) low-income energy efficiency (LIEE) services; and (5) the California Alternative Rates for Energy (CARE) Program.
AB 1890 specifies funding levels for the Public Benefit programs as follows:/
(1) Cost-effective energy efficiency and conservation activities for Edison shall be funded at not less than $90 million for 1998 though 2000 and $50 million for 2001;
(2) Research, development, and demonstration programs to advance science or technology that are not adequately provided by competitive and regulated markets for Edison shall be funded at not less than $28.5 million for 1998 through 2001;/
(3) In-state operation and development of existing and new and emerging renewable resource technologies shall be funded at not less than $49.5 million for 1998 through 2000 and $76.5 million in 2001 by Edison;/
(4) LIEE services and CARE programs provided to low-income electricity customers shall be funded at not less than the 1996 authorized levels based on an assessment of customer need. The 1996 authorized level for the LIEE program as adopted in the 1995 GRC Decision is $7.367 million. In addition, a 15% discount is provided to eligible lowincome customers through the CARE program and a CARE surcharge is billed to nonCARE customers to make up the revenue deficiency that results from the 15% discount./ The CARE surcharge is one component of total June 10, 1996 frozen rate levels and will therefore remain at its current 1996 level on January 1, 1998. Consequently, a forecast 1998 CARE revenue requirement is not required, with one exception described below.
Administrative costs associated with the CARE program and nonincremental administrative costs associated with the expanded CARE program are currently included in base rates pursuant to Decision No. 8909044. The 1995 GRC decision authorized an expense level of $757,000 for CARE administrative costs, which is currently reflected in 1996 base rate levels. The nongeneration PBR Decision 9609092 assigned this amount to nongeneration base rates (subject to CPIX) effective January 1, 1997. This CARE revenue requirement for administrative costs will be removed from nongeneration PBR rates and will be included in the Public Benefit charge effective January 1, 1998.
For the purposes of this testimony, Edison has assumed that the
levels of funding for Public Benefit programs as specified in
AB 1890 will be the 1998 Public Benefit programs' revenue
requirement as summarized in Table IV-3. The funding levels established
in AB 1890 for Public Benefit programs are the levels that
should be adopted by the Commission. Although the levels are
expressed in "notlessthan" terms in AB 1890,
the overall intent of the legislation including the
tariff freeze and rate reduction provisions makes
it clear that these levels should be adopted without modification.
CARE levels should continue to be based on need, just as they
are today. For Edison, the best indicator of need in our service
territory is the current level of funding for providing CARE benefits
to eligible lowincome customers.
January 1, 1998 Public Benefit Revenue Requirement (Excluding Current Care Surcharge Amounts) | ||
| Line No. | Public Benefit Program | 1998 Revenue Requirement |
| 1. | Energy Efficiency | $ 90,000 |
| 2. | Research and Development | $ 28,500 |
| 3. | Renewables | $ 49,500 |
| 4. | LIEE | $ 7,367 |
| 5. | CARE Admin. Costs | $ 757 |
| 6. | Subtotal - Program Expense | $ 176,124 |
| 7. | FF&U, CPUC Juris. / | $ 1,909 |
| 8. | Total 1998 Public Benefits Revenue Requirement | $178, 003 |
At this time, it is not known what portions of the above programs will be under utility administration or will be administered by a non-utility entity effective January 1, 1998. PU Code Section 381(f), however, states that the Commission shall provide for the transfer of all research and development funds other than those for transmission and distribution functions and all funds collected for in-state operation and development of existing and new and emerging renewable resource technologies to the California Energy Resources Conservation and Development Commission pursuant to administration and expenditure criteria to be established by the Legislature.
Commission decisions in 1997 resulting from the current working group efforts and reports on Public Benefit programs, could ultimately impact the conceptual Public Benefit ratemaking described below. Once Commission decisions are rendered in 1997 on Public Benefit programs, Edison will file tariffs and rates implementing the adopted ratemaking and revenue requirement by Advice Filing during the implementation phase of this proceeding in late 1997.
In addition to retaining the currently effective CARE surcharge and CARE balancing account mechanism, Edison will establish a separate non-bypassable Public Benefit charge effective January 1, 1998 to collect the annual Public Benefit revenue requirements for the programs listed in Table IV-3. Edison also anticipates the establishment of a Public Benefit Balancing Account (PBBA). Separate sub-accounts within the PBBA will be established to track costs and revenues for: (1) energy efficiency and conservation activities, (2) research and development, (3) renewable resources, and (4) LIEE services. Accumulated balances in the PBBA will accrue interest based on the monthly 3month commercial paper rate. The PBBA will ensure that no more and no less than Edison's authorized Public Benefit revenue requirements are ultimately collected from customers, through an annual "true-up" process where year-end under/over-collections will be reflected in the following year's forecast Public Benefit revenue requirement.
AB 1890 requires nuclear decommissioning costs to be recovered as a nonbypassable charge until such costs are fully recovered./ Edison will establish a separate nuclear decommissioning charge effective January 1, 1998 to collect the annual nuclear decommissioning revenue requirement. Edison also proposes the establishment of a Nuclear Decommissioning Balancing Account (NDBA) to track, on a monthly basis, the authorized nuclear decommissioning revenue requirement as compared to the recorded nuclear decommissioning charge revenues. Accumulated balances in the NDBA will accrue interest based on the monthly 3-month commercial paper rate.
The NDBA will ensure that no more and no less than Edison's authorized nuclear decommissioning revenue requirement is ultimately collected from customers. This will be accomplished through an annual "true-up" process where year-end under/over-collections will be reflected in the following year's forecast nuclear decommissioning revenue requirement.
Decision No. 95-07-055 directed Edison to file a study evaluating nuclear decommissioning funding no later than three years from the date of that decision. Our next study is due in July 1998. Edison proposes that the 1998 nuclear decommissioning revenue requirement remain at the current 1995 GRC authorized levels for rate recovery purposes, subject to later revision dependent on Commission action on the July 1998 decommissioning study. The 1995 GRC nuclear decommissioning revenue requirement currently reflected in rates, and proposed for 1998, is $103,897,000./
AB 1890 also states that recovery of nuclear decommissioning costs may be accelerated to the extent possible. As discussed in Edison's October 21, 1996 Amended Transition Cost Application, if, after recovering all authorized transition costs, the Transition Cost Balancing Account is overcollected, Edison will propose to the Commission to utilize the overcollected balance to either accelerate recovery of nuclear decommissioning costs or as a one-time bill credit to all retail customers.
In this application, Edison is requesting the Commission to explicitly adopt the following findings:
This section describes how Edison's rates will be unbundled into separate charges for energy, transmission, distribution,/ CTC, Public Benefit programs, and nuclear decommissioning costs to be implemented on January 1, 1998 consistent with the PU Code and the Commission's December 20, 1995 Restructuring Decision./ It describes how direct access customers will be charged for the ongoing transmission and distribution services provided by the utility and the nonbypassable charges for transition costs, Public Benefit programs, and nuclear decommissioning costs. It describes the 10% rate reduction for residential and small commercial customers contingent on the issuance of Rate Reduction Bonds, as well as the surcharge applicable to these customers to repay the costs of the bonds. Finally, it describes how Edison will unbundle certain special rates and contracts.
Section 368(a) of the PU Code requires that utilities "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. . . ." Therefore, the unbundling of rates into the six components listed above will not change the total rates charged to customers./ The functional rate unbundling set forth is required to facilitate competition in provision of generation services and to account for the different ratemaking treatment applicable to the various components.
Unbundling the generation costs is fundamental to the restructuring of the electric services industry. The generation rate will consist of two components: the PX energy charge and the CTC. Identification of the PX energy charge will enable customers to evaluate prices charged by alternative generation suppliers and by those offering bilateral contracts. Edison's proposal for determining the PX energy charge is described in Section B.1.a.
CTC must be unbundled to ensure its nonbypassability and to enable the separate tracking of transition cost recovery. In its Cost Recovery Plan filed with the Commission on October 15, 1996, Edison described how transition costs will be recovered subject to the rate freeze required by AB 1890 by subtracting the charges for energy, transmission, distribution, Public Benefit programs, and nuclear decommissioning from the frozen rate level. Section B.1.c describes in detail how transition costs will be collected from all customers through the nonbypassable CTC.
Establishment of the ISO requires unbundling the costs of the transmission facilities transferred to the ISO's control, since these facilities will become subject to FERC ratemaking for FERC jurisdictional services. Separate ratemaking treatment for transmission facilities requires specific identification of the transmission component in customers' rates. Edison's proposal for unbundling transmission rates is described in Section B.2.a.
The Restructuring Decision requires utilities to provide nondiscriminatory distribution service to all customers, including direct access customers, within their service territories./ Transparent prices for this service must accompany such nondiscriminatory access. Edison's proposal for unbundling distribution rates is described in Section B.2.b.
Section B.2.c describes Edison's proposals for establishing nonbypassable charges to recover the costs of Public Benefit programs and nuclear decommissioning as required by Sections 379 and 381 of the PU Code.
Appendix B to this exhibit contains illustrative unbundled January 1, 1998 rates for all of Edison's retail rate schedules. Development of final 1998 rates and tariffs must await completion of several critical path steps:
Edison plans to submit its final 1998 rates in late 1997 by Advice Filing following the resolution of these issues in the appropriate proceedings.
The total charges for generation were derived residually by subtracting all other related charges from the total rates frozen at June 10, 1996 levels./ The design of the other charges, including charges for transmission, distribution, Public Benefit programs, and nuclear decommissioning, is presented in Section B.2./ The total generation charge will be separated into the PX energy charge and the CTC. The CTC will be determined residually by subtracting Edison's cost of procuring PX energy over the billing period from the total generation charge. Direct access customers will not pay the PX energy charge, but will be responsible for paying the CTC.
It is anticipated that the UDC will submit its forecast demand for each hour of the day to the PX for scheduling purposes at least a day in advance. If the UDC's forecast is correct then the energy charge to the UDC will be the same as the dayahead posted PX price. In practice this outcome is unlikely and there will generally be differences between the dayahead forecast for a given hour, hourahead forecast for that hour, and the actual use by UDC customers during that hour. Under these circumstances, the UDC will incur additional costs for energy. The protocols for settling the energy imbalances are being considered in the ISO/PX Working Groups. The following describes Edison's proposed method of calculating the PX energy charge based on its understanding of how the ISO/PX will function./ If the final ISO/PX protocols are different from the assumed ones, Edison will modify its methodology accordingly.
Edison proposes that the PX energy charge be based on the weighted average of the dayahead and hourahead prices from the PX for the hour for which the charge is being calculated, with a trueup at a later date. This trueup would reflect any expost settlement costs from the PX for each hour as described below.
As shown in Figure V-1, the quantities purchased by the UDC at the spot prices in each hour will not be known until the ISO has received data on hourly demands of all nonUDC customers, including both customers with hourly meters and customers utilizing load profiles. For instance, for a customer utilizing load profile and having a billing cycle from April 30 to May 29, estimated hourly consumption on any hour of April 30 will not be known until that customer's meter is read on May 30. When the actual amount of energy purchased by the UDC in each hour has been determined, both UDC and direct access customers' bills for purchased energy will be truedup to reflect the full price paid by the UDC. This adjustment will occur when the meter reading cycle for all bundled service customers and the direct access customers utilizing load profiles has been completed and the PX and the UDC can determine the UDC's actual hourly consumption. As depicted in Figure V-2, this should occur no later than about 50 days after the end of the customer's billing period.
Retail Meter Reading System Information Flow Sample Calculation Of Hourly Usage For 30th Day Of April |
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Settlement Timeline |
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To illustrate this process, assume that during a given hour the UDC on a dayahead basis forecasts need for 100 MWh and submits this forecast to the PX. Based on forecasts of demand and supply by all market participants, the dayahead market clearing price is established at 3¢/kWh. An hourahead of time the UDC realizes that it has a need for 110 MWh of energy and requests that amount from the PX. The additional 10 MWh of energy will be billed at the hourahead PX price (assumed) of 3.2¢/kWh. Initially, the hourly PX energy charge the weighted average rate will be established at 3.018¢/kWh (((100x3) + (10x3.2))/110). The UDC will bill this amount during the current billing cycle. After all meters are read, it becomes apparent that the UDC utilized 115 MWh of energy. The 5 MWh will be settled at the PX spot price (assumed) of 3.3¢/kWh. At this point, the hourly PX energy charge will be updated to 3.030¢/kWh (((100x3) + (10x3.2) + (5x3.3))/115) and the trueup to the initial PX energy charge will be equal to .012¢/kWh.
Initially, the charge to each UDC customer for procuring energy from the PX (credit to direct access customers for procuring their own energy) will be determined at the end of a customer's billing period by multiplying Edison's weighted average cost per kWh of procuring PX energy (i.e., blending of the dayahead and hourahead PX prices) by the customer's total consumption over the same billing period. Edison's weighted average PX energy cost per kWh over a billing period for load profile customers will be calculated by multiplying the percent of load occurring in each hour (derived from the load profile) and the UDC's energy cost for that hour (e.g., 3.018¢/kWh in the above example). For customers with realtime meters, the actual recorded energy consumption is utilized instead of the hourly consumption estimated based on an assumed load profile. For customers taking service under a time of use rate schedule without realtime meters, the PX energy charge will be based on the average PX price during each time of use period over the billing cycle.
As discussed above, about 50 days after the customer's initial bill is rendered, the UDC receives its final hourly settlements from the ISO for the last day of the customer's billing cycle. Embedded in these settlements are the hourly spot prices and the amounts purchased by the UDC during each hour of the initial billing cycle. Dividing the total dollar amount of all hourly settlements by the total kWhs purchased by the UDC during those hours results in an average ¢/kWh adjustment for the original billing cycle./ Edison expects that these adjustments will be relatively small. Therefore, until it is proven otherwise in actual ISO/PX operations, Edison proposes to apply this adjustment to the customer's usage during the current billing cycle. As an example, suppose that a particular customer's billing cycles correspond to the calendar months. For the month of January, the customer receives a UDC bill based on the hourly PX energy charges which are weighted averages of the dayahead and hourahead prices (see the above paragraph). In the month of March when the final settlements for the month of January are known, in addition to the initial bill for the month of March, there will be a dollar adjustment on the customer's bill based on the ¢/kWh adjustment derived from the hourly settlements for January and kWh usage in March./
The procedure described here is consistent with the Restructuring Decision's requirement that "the distribution utility must simply pass on to these [full service] customers the cost of electric energy as revealed by the Exchange over the billing cycle."/ Furthermore, in compliance with PU Code Section 368(b), bills to direct access customers will be credited an amount equal to the PX energy charge for the energy they take from other sources, so that a direct access customer will pay the same unbundled component charges, other than energy, a bundled service customer pays.
Edison's proposal to use the weighted average price (including the trueup described above) as the energy price credited to direct access customers is appropriate because: (1) it provides the UDC with an incentive to accurately forecast its energy needs and minimize the settlement costs as a higher PX energy price results in a lower CTC level; (2) direct access customers are expected to pay for their own settlement costs and should not be credited only with the day-ahead PX energy price excluding the UDC's settlement costs;/ and (3) residual determination of CTC based on a dayahead PX energy price and a separate charge to recover the settlement costs from UDC customers would violate the rate freeze provision of AB 1890.
In addition to the energy charge, it is expected that there will be other charges assessed to the UDC by the ISO/PX. These charges include those for ancillary services, transmission congestion, and ISO/PX administrative fees./ The first two are anticipated to be hourly and measured in ¢/kWh; thus, they will be charged to the UDC customers and credited to the direct access customers who procure such services in the competitive market in the same manner as the PX energy charge. The administrative fee will be converted to a ¢/kWh charge by dividing the monthly fee by the monthly kWh consumption of the UDC customers.
Efficient settlement of the commercial transactions occurring among market participants is essential to the proper functioning of the new competitive electricity market. Even after the determination of settlements as described in the above section, there remain other imbalances in the system that must be identified and their costs recovered from all customers, including direct access customers. There are several causes for these imbalances.
First, imbalances result from the error in estimation of distribution losses. Distribution losses vary from hour to hour depending on load, but typically average about 6% within the distribution grid. The UDC will provide market participants with projected distribution loss factors for use in developing balanced load and generation supply schedules. Actual distribution losses will likely differ from the projected values resulting in imbalances in the system.
Second, most customers will not initially have realtime meters. Load profiles must therefore be used to assign aggregated consumption data to individual hours. These load profiles will not be precise, and as a result, there will be a discrepancy between the actual hourly usage of the load profile customers and their estimated hourly consumption.
Third, imbalances are also caused by energy theft, meter malfunctions, and other similar factors that result in actual energy consumption in UDC's distribution system differing from the measured amounts.
To describe how the hourly imbalances due to these factors
are measured in order to assign their financial impacts to all
customers, consider the system depicted in Figure V-3 where meters
D1 and D2 are RealTime Meters (RTMs) recording the usage
of two direct access customers represented by the scheduling coordinator
SC1. Direct access customers D3 and D4 utilize load profiles
in estimating their hourly usage and are represented by the scheduling
coordinator SC2. Metering points U1 and U2 represent UDC customers
utilizing RTM and load profile estimates, respectively. Point M
is the interface point between the ISO and the UDC. The scheduled
load at the customers' meters is 200 MW. Assuming system
losses of 20 MW, the total load scheduled at the ISO/UDC
interface will be 220 MW. After reading or estimating the
actual hourly load at the customers' meters, it is found that
a total of 220 MW was actually consumed. The 20 MW
difference will be settled with individual scheduling coordinators
as described in Section (a) above./
If during this hour 250 MW is delivered at point M
then there is an imbalance of 30 MW which is due to errors
in estimating losses and load profiles as well as theft. Edison
proposes that the cost of such imbalances be recovered from all
customers as a component of the nonPBR distribution rate.
It should be noted that there is no way to divide such imbalances
between the several factors potentially causing them or to identify
whether they result from the UDC or direct access transactions.
Example Of Imbalance Measurement |
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The CTC will be determined residually by subtracting the PX energy charge from the total generation charge. Residual determination of the CTC allows for rates to be unbundled while adhering to the rate freeze required by PU Code Section 368. The only way to ensure that total rates for all customers do not change during the term of the rate freeze is to match variations in the PX energy charge with offsetting variations in the CTC. The residual CTC ensures that the sum of all rate components equals the frozen total rate levels.
Residual determination of the CTC complies with the requirement in PU Code Section 367(e) that transition costs "be allocated among the various classes of customers, rate schedules, and tariff options to ensure that costs are recovered from these classes, rate schedules, contract rates, and tariff options, including self-generation deferral, interruptible, and standby rate options in substantially the same proportion as similar costs are recovered as of June 10, 1996, through the regulated retail rates of the relevant electric utility . . ." and that "individual customers shall not experience rate increases as a result of the allocation of transition costs . . . ." The portion of the rate remaining once all economic and other nonbypassable charges are accounted for reflects uneconomic costs embedded in current bundled rates. When these other charges are unbundled and subtracted from the total, the residual is the CTC.
The Restructuring Decision suggests an allocation of transition costs using an equal percent of marginal cost methodology "unless specific circumstances justify a different approach."/ Here, such circumstances exist. An EPMC allocation of transition costs would result in changes to the total rates paid by customers in violation of AB 1890 and the Commission's policy against cost shifting unless all other revenue components were also allocated by EPMC. At least one component, the PX energy charge, will not be allocated by EPMC, but will be market based. As previously described, the PX energy charge will be based on customers' energy consumption and PX prices during the billing period. Therefore, circumstances justify a different approach than that indicated in the Restructuring Decision such as Edison's proposal to determine CTC residually in order to avoid costshifting.
Advice Letter 1191-E, implementing D.96-09-092 in Edison's nongeneration PBR proceeding, separated the expected 1997 total base rates into generation and nongeneration base rates and described the method Edison will use for adjusting the nongeneration base rates in subsequent years according to a CPI-X update rule. In this filing, Edison proposes to separate the expected 1998 nongeneration base rates into charges for transmission and distribution PBR as discussed in Chapter IV. The rates contained in this filing are dependent upon the 1997 nongeneration base rates eventually authorized by the Commission, and will be modified if the nongeneration base rates implemented on January 1, 1997 are different than those contained in Advice Letter 1191E./ Since total rates cannot change due to AB 1890, any changes to the nongeneration base rates will be exactly offset by changes to the residually determined generation rates as previously described in Section B.1.
Total distribution rates will be made up of two components in 1998: a PBR distribution rate and a non-PBR distribution rate or Miscellaneous Adjustment Mechanism Billing Factor (MAMBF). The revenue requirement associated with the MAMBF is discussed in Section D.1.b of Chapter IV. Edison's proposed rate design for the PBR distribution rate and MAMBF are described in Section B.2.b, below.
In Advice Letter 1191-E, Edison separated its expected 1997 base rates into generation and nongeneration base rates using the methodology adopted in Phase 2A of its 1995 GRC (D.9604050) and the sales forecast adopted in Edison's 1996 ECAC (D.9602071). Nongeneration base rates were developed using an EPMC allocation of nongeneration base revenues to rate groups, and the generation base rates were determined residually./ Therefore, total base rates were unaffected by the separation into generation and nongeneration components. As described in Chapters III and IV, Edison has revised its separation of costs between generation and nongeneration from that which was used to design the nongeneration base rates contained in Advice Letter 1191-E. Accordingly, Edison has redesigned the 1997 nongeneration base rates, and proposes to use them as the starting point for the 1998 nongeneration base rates after escalating them by CPIX for 1997./ Thus, Edison has not changed the method by which the nongeneration base rates were designed. Edison will then separate the 1998 nongeneration base rate into transmission and distribution PBR components. The increase in nongeneration base rates, whether from application of the update rule or the revised cost separation, is offset by a reduction in the generation rates and therefore a reduction in the amount of transition costs that can be recovered through the CTC under the rate freeze.
Edison proposes to design transmission rates using an EPMC method to recover the 1998 FERC authorized transmission revenue requirement as described below. Edison expects to file its proposed transmission revenue requirement with FERC in March 1997, based on FERC's final determination of which facilities are transmission-related and are transferred to the ISO's control, and which are distribution-related. For purposes of this filing, Edison has provided in Chapter IV an illustrative estimate of the 1998 FERC transmission revenue requirement. The transmission rates contained in this filing are preliminary and will be modified if the FERC authorized transmission revenue requirement is different than Edison's illustrative transmission revenue requirement described in Chapter IV./ Any differences between the transmission rates developed here and those which result from use of the FERC authorized transmission revenue requirement will also impact the distribution rates discussed in Section 2.b./
It has not yet been resolved whether FERC or the Commission will have responsibility for the design of retail transmission rates. For this filing, Edison has assumed that FERC will authorize the transmission revenue requirement for FERC Jurisdictional services and defer jurisdiction over the design of retail transmission rates to the Commission./ This model provides comparable treatment for bundled service and direct access customers as required by PU Code Section 368(b), since all retail customers would pay the applicable Commission authorized retail transmission rate. In this scenario, the 1998 nongeneration base rates can be separated between transmission and distribution by first designing transmission rates to collect the 1998 FERC transmission revenue requirement, and then subtracting the appropriate portion of transmission rates from the 1998 nongeneration base rates.
Edison's proposed transmission rates were designed using the EPMC method consistent with the current design of total nongeneration base rates. Edison used the transmission component of marginal cost revenue responsibility adopted in Phase 2A of its 1995 GRC to allocate the transmission revenue requirement to rate groups. Each rate group's percentage of system marginal transmission cost revenue responsibility was multiplied by the appropriate portion of the transmission revenue requirement to determine the amount of the transmission revenue requirement allocated to each rate group.
Edison recognizes that the transmission facilities defined for developing the marginal transmission costs in Edison's 1995 GRC are different than the transmission facilities that will be transferred to the ISO's control and for which transmission rates are being designed in this proceeding. However, Edison sees little value in relitigating the marginal cost models used to allocate the transmission revenue requirement to rate groups since adjusting the unit marginal transmission cost to reflect the revised definition of transmission facilities would have no effect on the transmission revenue requirement allocated to each rate group./ Such an adjustment would change each rate group's marginal transmission cost revenue responsibility by the same factor, so their proportion of the total, on which the transmission revenue requirement allocation is based, would be unaffected.
Transmission rates were designed to recover the transmission revenue requirement allocated to each rate group. For rate schedules with demand charges, the demand charges were set equal to the marginal transmission costs adopted in Phase 2A of the 1995 GRC and then scaled uniformly so that the charges recover the allocated transmission revenue requirement by rate group. In addition to ensuring that the transmission rates collect the transmission revenue requirement allocated to each rate group, the scalar partially adjusts the marginal transmission costs for the reclassification of nonISO transmission facilities as distribution facilities. The scalar is less than one, reflecting that only a portion of what was defined as transmission for purposes of developing unit marginal transmission cost in Phase 2A of Edison's 1995 GRC is now part of the transmission revenue requirement.
If the scaled charge would exceed the total nongeneration demand charge, it will be set equal to the total nongeneration demand charge, and Edison proposes that the remaining revenue requirement be collected in energy charges so that the rate freeze is not violated. If the scaled charge is less than the total nongeneration demand charge, Edison proposes that the remainder of the nongeneration demand charge will be applied to the distribution charge or CTC as appropriate. For purposes of rate design and consistent with the rate design principles used in Phase 2A of Edison's 1995 GRC and the design of nongeneration base rates contained in Advice Letter 1191E, 90% of the adopted marginal transmission costs were considered coincident demand-related and 10% were considered noncoincident demand-related./ Annual coincident marginal transmission costs were allocated to seasons and time of use periods by the relative loss of load probability occurring during the time period. For example, approximately 21% of loss of load probability occurs during a summer month's on-peak period, so the on-peak marginal demand cost is equal to 21% of the coincident marginal transmission cost. By definition, noncoincident marginal transmission costs do not vary by time period. Thus, the annual noncoincident transmission cost is converted to monthly values by dividing by 12.
For rate schedules without demand charges, transmission rates were designed on a cents per kWh basis by dividing the allocated transmission revenues by total kWh sales/ to the rate group.
Distribution rates subject to PBR were determined by subtracting the appropriate portion/ of transmission rates from the 1998 nongeneration base rates so that the total 1998 nongeneration base rates are not impacted by the separation into transmission and distribution components. These distribution rates are subject to the CPIX update rule in 1999 and subsequent years.
In D.9609092, the Commission adopted a nongeneration PBR to take effect on January 1, 1997, as well as rules for a distributiononly PBR which it authorized to extend through December 31, 2001./ In doing so, the Commission explained its procedural plan as follows:
[W]e order Edison to file tariffs which set separate rates for generation and nongeneration base revenue requirement effective January 1, 1997; and we will order Edison to file changes to these tariffs as part of our unbundling proceeding within 60 days after FERC and this Commission have completed the separation of Edison's nongeneration business into transmission and distribution and we will order that Edison file these tariff changes with an effective date coordinated with the beginning of FERC set transmission rates./
In its nongeneration PBR filing, Edison had proposed an annual revenue credit that would determine annual authorized distribution PBR revenues as the difference between annual CPUCauthorized nongeneration revenues and FERCauthorized transmission revenues. In its decision on Edison's nongeneration PBR, the Commission expressed two concerns with this revenue credit approach./ First, the Commission did not want to blur the jurisdictional line between FERC and itself by compensating Edison for fluctuations in transmission revenue requirement by changing the distribution rates. Second, the Commission expressed reservations about the use of a revenue credit approach in conjunction with its adopted rate PBR.
Edison's initialyear rate credit proposal remedies both of these concerns. The rate credit approach is used only in 1998 to establish the starting point for a distribution rate PBR and after that point the distribution rates will not be adjusted for fluctuations in the transmission revenue requirement. Furthermore, FERCadopted transmission revenue requirement will be used to calculate transmission rates based on the projected billing determinants in the Test Year and this allows a rate credit approach to be used with a rate PBR.
A separate, cents per kWh billing factor was established for the NonPBR component of distribution rates described in Chapter IV to enable the separate tracking of revenues required for operation of the MAM balancing account. The MAMBF is derived by dividing the forecast 1998 MAM revenue requirement by total system kWh sales. Edison proposes a simple, equal cents per kWh design for the MAMBF because: (1) there is no discernible cost basis for allocating the revenues associated with the MAMBF to rate groups; (2) the MAMBF will not impact any customer's total rate due to the rate freeze; and (3) the MAMBF can easily be adjusted as needed to reflect balances in the MAM account without the need to establish billing determinant forecasts for each rate group.
Edison has developed nonbypassable charges for Public Benefit programs and nuclear decommissioning costs pursuant to AB 1890. Referring to Public Benefit programs, Section 381(a) of the PU Code states that "the Commission shall require each electrical corporation to identify a separate rate component to collect the revenues used to fund these programs. The rate component shall be a nonbypassable element of the local distribution service and collected on the basis of usage." Accordingly, the Public Benefit programs charge was derived by dividing the 1998 revenue requirement for Public Benefit programs by total system kWh sales. The administrative costs of operating the CARE program, which provides low income customers with discounted electricity rates, are included in the revenue requirement for Public Benefit programs as discussed in Chapter IV, but the funding for the CARE discount will be collected in a separate charge consistent with current practice. A separate surcharge is necessary because not all customers are subject to the CARE surcharge,/ whereas all customers are subject to the Public Benefit programs charge. The CARE surcharge and Edison's proposals for reflecting the CARE discount in unbundled rates are described in Section B.4.
A similar method was used to derive the nonbypassable nuclear decommissioning charge required by Section 379 of the PU Code: "Nuclear decommissioning costs shall not be part of the costs described in Sections 367, 368, 375, and 376, but shall be recovered as a nonbypassable charge until the time as the costs are fully recovered." The nuclear decommissioning charge was derived by dividing the revenue requirement for nuclear decommissioning by total system kWh sales.
Residential rate schedules, except Schedule TOUD2, charge a lower rate for an initial "baseline" quantity of usage, and a higher rate for monthly usage in excess of the baseline quantity, in accordance with state law./ The rate freeze required by AB 1890 maintains the existing total residential baseline and nonbaseline rates. As rates are unbundled, Edison proposes to reflect the baseline/nonbaseline rate differential exclusively in the CTC. This is appropriate because the expected 1998 nongeneration base rates determined by the CPI-X update rule are the same for baseline and nonbaseline kWh usage, so the differential must be reflected in the generation portion of the rate. In the 1997 rates filed in Advice Letter 1191-E, the baseline/nonbaseline rate differential is reflected exclusively in the ECABF portion of the rate. As discussed in Chapter IV, the ECABF will be eliminated in 1998, and the majority of its associated revenue requirement will become part of the generation charge. As the generation charge is unbundled into the PX energy charge, which does not vary between baseline and nonbaseline usage, and the CTC, the rate differential will be reflected exclusively in the CTC. From residential customers' perspectives, it is immaterial which component reflects the rate differential over the term of the rate freeze since their total rate will not change. Since the CTC is a nonbypassable part of the customer's rate, baseline rates will continue for both bundled service and direct access residential customers. Once the rate freeze period has ended, it may be appropriate to reflect the baseline/nonbaseline rate differential in distribution rates, and Edison expects to address this issue in future rate proceedings.
The CARE program provides a 15% discount to participating low income customers. Funding for the CARE discount is provided by a cents per kWh surcharge added to customers' rates and will continue at current levels as required by PU Code Section 382./ The CARE discount will apply equally to both bundled service and direct access customers. Bundled service residential customers take service on Schedule DCARE which currently reflects the CARE discount in the basic charge and as a negative CARE surcharge. Edison proposes to continue to reflect the CARE discount in this manner.
The CARE discount also applies to certain customers served on general service rate schedules, such as facilities which are group living quarters housing low income residents. These customers are not served under a separate rate schedule, but are served on the standard rate and then provided with a 15% discount. In order to maintain the same level of discount currently provided to CAREeligible customers, those who choose direct access will have their CARE discount calculated based on the total rates before subtracting the PX energy charge.
AB 1890 Section 1(e) directs the investor-owned utilities to "apply concurrently for financing orders from the Public Utilities Commission and rate reduction bonds from the California Infrastructure and Economic Development Bank in amounts sufficient to achieve a rate reduction in the most expeditious manner for residential and small commercial customers of not less than 10 percent for 1998 and continuing through March 31, 2002"./ PU Code Section 368(a) specifies that the 10% reduction will be applied to Edison's rates that are in effect as of June 10, 1996. Edison's proposals for reflecting the 10% rate reduction on residential and small commercial customers' bills and for designing the bond financing charges applicable to these customers are discussed below./ The actual bond financing charges will be developed as part of the Rate Reduction Bond Application filed with the Commission by June 1, 1997. If circumstances justify a different approach to developing the bond financing charges, Edison will modify its proposals at that time.
The 10% rate reduction will apply to all customers in the Domestic and GS1 rate groups./ PU Code Section 331(h) defines "small commercial customer" as a customer that has a maximum peak demand of less than 20 kW. This definition corresponds to all customers served on rate schedules in Edison's GS1 rate group. As defined in Edison's tariffs, these rate schedules are not applicable to customers with maximum demands in excess of 20 kW. While some customers with peak demands of less than 20 kW are served on agricultural and pumping, street lighting, and traffic control rate schedules, Edison does not consider agricultural and governmental customers as part of the commercial class. Other portions of AB 1890 make clear the intended distinction between commercial and agricultural customers by referring separately to residential, commercial, agricultural, and industrial customers./
To ensure that each residential and small commercial customer is provided with a 10% rate reduction, the total bill will be calculated at rate levels in effect on June 10, 1996 and then reduced by a 10% bill credit. For direct access customers, the discount will be applied to the total bill before subtracting the PX energy charge, so that they receive the same 10% reduction they would have received by remaining bundled service customers. The bill credit will be reflected as a reduction in CTC collected from residential and small commercial customers. Revenues for PX energy, transmission, distribution, Public Benefit programs, and nuclear decommissioning costs will not be impacted by the rate reduction.
A charge will be established to fund the principal, transaction costs, and interest associated with the Rate Reduction Bonds. The charge will be added to the charges for PX energy, transmission, distribution, Public Benefit programs, and nuclear decommissioning costs before these charges are subtracted from total rates to determine the CTC applicable to residential and small commercial customers. Since the CTC will be decreased by an amount equal to the Rate Reduction Bonds surcharge, total rates will not be impacted by this additional charge.
Edison will design separate charges for residential and GS1 customers to reflect the absolute differences in rate reductions between the two rate groups. Since a 10% rate reduction is greater on a cents per kWh basis for GS-1 customers than for Residential customers, separate charges are needed to avoid cross subsidies between Residential and GS1 customers in the period after the rate freeze but before the bonds are fully repaid. The proposed charges and associated ratemaking will be contained in the Rate Reduction Bond Application filed with the Commission by June 1, 1997. Edison will develop the charges by allocating the revenue requirement associated with the Rate Reduction Bonds to the eligible rate groups based on percent of total revenues using 1998 billing determinants and dividing the revenues allocated to each rate group by their respective kWh sales forecast for 1998.
Customers who become ineligible for service under one of the rate schedules eligible for the 10% rate reduction will no longer receive the bill credit nor be required to pay the charge for repayment of the Rate Reduction Bonds./
Customers on Edison's interruptible rate schedules currently pay discounted rates in exchange for agreeing to curtail a portion or all of their load upon notification by Edison./ The interruption criteria in Edison's tariffs allow for interruption during generation capacity shortages on the Edison system. According to PU Code Section 743.1, the level of interruptible credits can not be changed from the levels in effect on January 30, 1993 until March 31, 2002. In addition, the total rates charged to interruptible customers are subject to the rate freeze provision of AB 1890. Edison proposes to unbundle the interruptible rates in the same manner as its other rate schedules. In the 1997 rates filed in AL 1191E, the interruptible credit is reflected in the ECABF and the generation portion of base rates, which will become part of the total generation charge in 1998. Therefore, the interruptible credit will be reflected in the CTC charged to interruptible customers.
With the advent of the ISO and the PX, Edison will no longer dispatch generation nor will Edison have an obligation to plan for the generation needs of the customers in its service territory. As a UDC, Edison will meet its bundled service customers' energy needs through purchases from the PX./ UDC control of an interruptible program that is based on generation shortages is not compatible with the new industry structure, so Edison believes control of the interruptible program should be transferred to the ISO. The ISO would likely require changes to the interruption criteria to suit its requirements for reliable operation of the state's electric grid./ ISO control will provide for comparable treatment of direct access and bundled service interruptible customers, and should avoid concerns regarding possible discriminatory operation of the interruptible program in favor of bundled service customers which may arise if the UDC were to retain operational control of the program. Once details of the ISO interruptible program become available, Edison will modify its interruptible tariffs accordingly.
PU Code Section 368 requires setting rates for contracts or tariff options at levels equal to those in effect as of June 10, 1996. Among the special rate options and contracts that existed on June 10, 1996 and that therefore should receive special treatment to comply with this section are Edison's SelfGeneration Deferral Rate (SGDR) contracts and tariff options such as RealTime Pricing (RTP), Incremental Sales Rate (ISR), and Spot Pricing Amendment (SPA).
For eligible purchases under SGDR contracts,/ the CTC billing factor will be calculated residually in the same manner as that described in Section B.1.b for the otherwise applicable tariff. As a result, the discount provided to the SGDR customers will be reflected in a lower CTC billing factor and a lower amount of CTC revenues recorded in the CTC balancing account.
Under the ISR and SPA options, the eligible customers can purchase incremental energy at Edison's shortrun avoided energy and capacity costs plus a preestablished ¢/kWh adder./ Edison proposes to set the CTC billing factor for those options equal to the preestablished adders under each option after subtracting the nonbypassable Public Benefit and decommissioning charges. Also, Edison proposes to replace the avoided cost of energy and capacity by the PX energy charge when the PX price is used for payment to the Qualifying Facilities. For the RTP options, the generation charges vary by hour. Hourly PX energy charges will be subtracted from these hourly generation rates to determine the hourly CTC billing factors. Therefore, under RTP options, the CTC billing factors will also vary by hour.
In this application, Edison is requesting the Commission to explicitly adopt the following findings related to the functional unbundling of its rates.
In Decision 96-03-022, the "Roadmap Decision," the Commission noted that pending and future filings, new compliance filings as a result of restructuring, considerations to modify the ERAM and new PBR filings, "must all be coordinated in a manner that is most efficient and workable for all concerned." The Commission indicated that it would be appropriate to restructure regulatory proceedings in order to streamline and properly account for the new competitive environment./ In this chapter, Edison presents its proposals for establishing new regulatory proceedings to replace current proceedings that are no longer necessary. It should be noted that these proposals pertain to the period of the rate freeze mandated by AB 1890 which eliminates the need for most proceedings currently established to forecast various components of the utilities' revenue requirements. Edison will submit its proposals for proceedings necessary after the year 2001 at a future date.
Edison's current retail ratemaking can be separated into four principal components: (1) base rate revenue authorization procedures; (2) offset clause recovery procedures; (3) rate design proceedings; and (4) other miscellaneous filings.
Base rates have been authorized by the Commission to recover, on a forecast basis, non-fuel operation and maintenance (O&M) expenses and investment-related costs, including depreciation, nuclear decommissioning costs, taxes, and a reasonable return on authorized rate base./ The current Rate Case Plan provides for a GRC which is filed every 3 years. Phase 1 of the GRC establishes the Company's base rate revenue requirement, portions of which are adjusted annually through a Cost of Capital proceeding and an Operational Attrition filing.
Offset clauses were established by the Commission to recover specified costs, generally on a "dollar-for-dollar" basis. Edison's major offset clause is the ECAC which recovers most of Edison's fuel, fuelrelated and purchased power costs. The Company files an ECAC application annually to set the ECAC billing factors to recover forecast expenses. Any difference between the revenue generated by the ECAC billing factors and the recorded ECACincludable expenses is accumulated in the ECAC balancing account and then collected from or returned to customers in the following year. In addition, the Company must make a showing as to the reasonableness of its prior year's operations and the costs incurred. Any costs found by the Commission to have been unreasonably incurred are disallowed recovery.
Pricing policies and the methodologies for assigning revenue responsibility to various rate groups and the designing of rates are determined in Phase 2 (Pricing phase) of the GRC. The adopted principles are also used for setting rates in the intervening ECAC proceedings.
In addition to Phase 2 of the GRC, an annual rate design window proceeding can be utilized between GRCs by utilities and other parties to propose modifications to pricing structures as long as the revenue allocation results authorized in the pricing phase of the GRC are not modified.
In addition to the GRC and ECAC filings, other miscellaneous filings (including both application and Advice Filings) are required either as a result of the current Rate Case Plan, Commission orders, or on an asneeded basis. Examples of these miscellaneous filings include: (1) DSM Annual Earnings Assessment Proceeding; (2) Affiliate Reporting OIR; (3) G.O. 131D Permits to Construct and Certificates of Public Convenience and Necessity; (4) DSM/RD&D Fund Shifting; (5) Affiliates Transactions Audit; (6) Rules of Practice and Procedure; (7) Special Request Filings; and (8) various Commission established Investigations/Rulemakings. Edison is proposing no changes to these miscellaneous filings in this application.
Both electric restructuring and the rate freeze mandated by AB 1890 have eliminated the need for many of Edison's current ratemaking proceedings. The base rate revenue authorization procedure for distribution will be through a PBR mechanism. Transmission revenue requirements for facilities under the ISO's control will be set by FERC. The generation-related base revenues along with the fuel-related expenses will either be recovered through market revenues or will become part of the transition costs which will be subject to balancing account recovery. There will be other balancing accounts established to monitor the recovery of the costs of nuclear decommissioning and Public Benefit programs. All of these combined eliminates the need for the current GRC, Cost of Capital, Attrition, and ECAC proceedings./
Furthermore, as described in Chapter V, Edison plans to establish the CTC on a residual basis by subtracting the charges for transmission, distribution, etc. from the frozen rate levels. Therefore, during the rate freeze period the importance of rate design proceedings will diminish and changes in the level of CTC, Public Benefit and decommissioning charges can be accomplished through Advice Filings. In the following sections we describe in more detail the new ratemaking procedures that will need to be established during the rate freeze period.
On September 20, 1996, the Commission adopted a nongeneration PBR mechanism for Edison and required that a compliance Advice Letter be filed within 30 days of the effective date of the Decision to implement the authorized PBR mechanism effective January 1, 1997. Edison filed Advice Letter 1191-E on October 22, 1996.
The nongeneration PBR decision orders Edison to submit an annual report which is similar to the report filed by SDG&E in its compliance with the decision on its PBR Base Rate Mechanism (D.94-08-023).
D.94-08-023 requires SDG&E to file two annual reports: (1) its formulabased revenue requirement for the upcoming year on October 15th, for changes to be effective on January 1st of the new year; and (2) an Advice Filing on May 15th of each year that analyzes the results of the previous year against the PBR's performance benchmarks, and the resulting ratemaking adjustments. Edison will file two annual reports similar to those required of SDG&E by D.94-08-023, except that the information will not be identical due to the differences between the PBR mechanisms adopted for Edison and SDG&E./
Edison's proposed preliminary statement Part BB, Nongeneration Base Rate Adjustment Mechanism (NBRAM), in Advice Letter 1191-E, describes the contents of the annual Advice Filing that Edison will make on November 1st of each year regarding changes to Nongeneration base rates to be effective the following January 1st. This filing corresponds to the October 15th annual report required of SDG&E by D.9408023.
The Purpose of the NBRAM is to annually adjust the nongeneration base rates for escalation and a specified Productivity Pledge as authorized in D.9609092. The NBRAM shall be effective from January 1, 1997 through December 31, 2001 as authorized by the Decision, or beyond December 31, 2001 if authorized by the Commission./
An Advice Filing in compliance with D.96-09-092 will be submitted no later than November 1 annually. The Advice Filing will set forth:
Edison's nongeneration PBR Advice Letter also describes the PBR Exclusions. An Excluded Item is any item for which the base rate revenue requirement associated with the exclusion is not subject to recovery through Nongeneration Base rates. Rate recovery of Excluded Items may be determined in separate proceedings and shall be subject to recovery mechanisms other than Nongeneration Base Rates.
Edison's proposed Preliminary Statement Part CC, Base Rate Performance Mechanism (BRPM), in Advice Letter 1191E describes the contents of the annual Advice Filing that Edison will file on March 31 to report the results of the PBR revenue sharing and performance mechanisms for the prior calendar year. Edison's annual March 31 Advice Filing will contain the results and any necessary ratemaking adjustments for the nongeneration PBR revenue sharing mechanism and performance mechanisms for the prior calendar year including the results of the (1) service reliability performance mechanism; (2) customer satisfaction performance mechanism; and (3) employee health and safety performance mechanism. This filing corresponds to the May 15th annual report required of SDG&E by D.9408023.
In addition, the March 31 Advice Filing will include: (1) Edison's request, if any, for recognition of and recovery of Potential Z-factors; and (2) details of the operation of Edison's Base Rate Performance Mechanism.
As a result of the rate freeze, Edison believes that the importance of an annual forecast proceeding to determine January 1 revenue requirement and rates has been diminished. Again, distribution rates will be authorized through PBR Advice Filings as described above; transmission revenue requirements will be authorized by the FERC; and generation rates (including CTC) will be set residually. There does, however, remain a need to file on an annual basis with the Commission, forecast revenue requirements and rates for Public Benefits, nuclear decommissioning, and miscellaneous other costs (proposed for recovery through the MAM balancing account as discussed in Chapter IV).
On November 1 of each year, Edison proposes to make an Advice Filing to establish rate levels to be effective on January 1 of the following year. This Advice Filing would include all of the information needed for Commission review in order to set January 1 rates, including:
Items (1) through (3) above will all be subject to balancing account treatment (see Chapter IV) and the Commission will have ample opportunity to review the recorded operation of these accounts in Edison's proposed annual Reasonableness filing as discussed in the next section.
This November 1 Advice Filing would fully develop January 1 rate levels by starting with frozen June 10,1996 rates and subtracting out: (1) the PBR component of the distribution rate as filed in the November 1 Distribution PBR Advice Filing; (2) FERC/Commissionadopted transmission rates based on the FERCauthorized transmission revenue requirement; and (3) the proposed nuclear decommissioning, Public Benefit, and MAM rates to residually determine the generation rates./
Edison would file the November 1 Advice Filing with complete supporting documentation to allow interested parties to review the request. Any protests would be filed within the standard 20day protest period. Edison is proposing that the Commission issue a resolution adopting the November 1 Advice Filing no later than the last Commission conference of the year so that the rate changes can be effective January 1 of the following year.
On April 30 of each year, Edison proposes to file a Report with the Commission documenting balancing account entries for the prior calendar year. This April 30 Balancing Account Report will provide the appropriate forum for all interested parties to review and audit Edison's recorded balancing accounts. The Report would be subject to full discovery and, if necessary, evidentiary hearings. Edison requests that the Commission issue a resolution by December of the same year asserting that Edison's balancing account entries are appropriate and correctly stated./
This Report would include all of the information needed for the Commission to issue resolution on the recorded 12month calendar year balancing account entries for the following accounts:
Edison proposed in its July 15, 1996 Generation PBR application a greatly reduced scope of ECAC reasonableness./ Edison attaches as Appendix E to this testimony a copy of the ECAC and Reasonableness Review Revisions Testimony. This filing includes those items which, consistent with Appendix E, would have been included in an ECACtype reasonableness review. In the event Edison's Generation PBR proceeding is delayed such that it becomes clear that a decision may not be issued before January 1, 1998, Edison will propose that the ECAC and Reasonableness Review Revisions Testimony be addressed in this or another appropriate proceeding so that it may be decided before January 1, 1998.
On April 30 of each year, Edison proposes to file a Reasonableness Application covering the items listed below for the prior calendar year. The application would be subject to full discovery and, if necessary, evidentiary hearings. Edison requests that the Commission render a decision on each annual Reasonableness application by December of the same year.
This application would include all of the information needed for Commission review in order to issue a finding of reasonableness on the recorded 12month calendar year of operations and will be limited to the following items:
In this application, Edison is requesting the Commission to explicitly adopt the following findings related to future regulatory proceedings:
SOUTHERN CALIFORNIA EDISON COMPANY QUALIFICATIONS AND PREPARED TESTIMONY OF GAIL M. GUNSALUS
Q. Please state your name and business address for the record.
A. My name is Gail M. Gunsalus, and my business address is 2244 Walnut Grove Avenue, Rosemead, California 91770.
Q. Briefly describe your present responsibilities at the Southern California Edison Company.
A. I am the Supervisor of Pricing Design in the Regulatory Policy and Affairs Department. My responsibilities include development of present rate revenues, marginal cost revenue responsibility, revenue allocation, rate design, and the preparation of other pricing design studies.
Q. Briefly describe your educational and professional background.
A. I hold a Bachelor of Arts Degree in Economics and Political Science from the University of Arizona, Tucson, Arizona; and a Master of Science Degree in Economics from Arizona State University, Tempe, Arizona. I began working as a Tariff Analyst for Southern California Edison in 1992 and was promoted to my current position in 1995.
Q. What is the purpose of your testimony in this proceeding?
A. The purpose of my testimony in this proceeding is to sponsor Appendix B, "Supporting Rate Component Tables" of SCE1.
Q. Was this material prepared by you or under your supervision?
A. Yes, it was.
Q. Insofar as this material is factual in nature, do you believe it to be correct?
A. Yes, I do.
Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best judgment?
A. Yes, it does.
Q. Does this conclude your qualifications and prepared testimony?
A. Yes, it does.
SOUTHERN CALIFORNIA EDISON COMPANY QUALIFICATIONS AND PREPARED TESTIMONY OF JOHN R. FIELDER
Q. Please state your name and business address for the record.
A. My name is John R. Fielder, and my business address is 2244 Walnut Grove Avenue, Rosemead, California 91770.
Q. Briefly describe your present responsibilities at the Southern California Edison Company.
A. I am Vice President of Regulatory Policy and Affairs. My organization is responsible for regulatory policy and matters involving state and federal regulatory bodies.
Q. Briefly describe your educational and professional background.
A. I received a Master of Business Administration from UCLA in 1970 and a Juris Doctor Degree from Pepperdine University in 1978. I am a member of the State Bar of California.
Upon graduation from UCLA in 1970, I was employed by the Organization and Procedures Department of Southern California Edison. Three months later I was called to active duty in the Army and served three years. I returned to Southern California Edison and joined the Data Processing Department (now Information Services). I held supervisory positions in Administration, Quality Assurance, and Technical Support. In 1987, I became Manager of Information Services, and on January 1, 1989, V ice President responsible for Information Services. On February 1, 1992, I assumed my current position.
Q. What is the purpose of your testimony in this proceeding?
A. The purpose of my testimony in this proceeding is to sponsor Section II, "Policy Principles" of SCE1.
Q. Was this material prepared by you or under your supervision?
A. Yes, it was.
Q. Insofar as this material is factual in nature, do you believe it to be correct?
A. Yes, I do.
Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best judgment?
A. Yes, it does.
Q. Does this conclude your qualifications and prepared testimony?
A. Yes, it does.