IV. Elements of Cost Responsibility Applicable to MDL Customers

A. DWR Bond Charge

Pursuant to AB1X, the State of California has sold bonds to finance DWR's undercollections. The California Water Code authorizes the Commission to implement recovery of both of DWR Bond and Power charges so that DWR can recover its costs incurred from retail end use customers in the service territories of the three major IOUs (Water Code, §§ 80110 and 80134).

In D.02-02-051, the Commission adopted a "Rate Agreement" governing the terms by which the Bonds would be administered, and establishing a framework for discharging DWR's and the Commission's statutory obligations set forth in AB 1X, as amended by SB 31X (referred to hereafter as "the Act"). Under the Act, the Commission must impose charges on electric customers sufficient to compensate DWR for its costs under the Act, including power procurement, and bond principal and interest.

Revenue streams both from bond and power charges were necessary for DWR to support bonds with investment-grade ratings. D.02-12-082 and D.02-11-074 (amending D.02-10-063 on rehearing) adopted the process to implement DWR Bond Charges for bundled customers. D.02-11-022 adopted Bond Charges for DA customers. DWR Bond Charges applicable to MDL customers are being addressed in this phase of the proceeding.

1. Parties' Position

The IOUs and ORA propose to charge MDL customers for DWR Bond Charges on the same basis as authorized for bundled and DA customers. The IOUs and ORA argue that MDL customers bear responsibility for Bond Charges in conformance with AB 117 in order to avoid cost shifting to bundled customers. The IOUs and ORA propose that the same Bond Charge apply to MDL as is applicable to bundled customers and oppose any offset (such as that proposed for Customer Generation DL customers in a separate phase of this proceeding).

CMUA and Merced concede MDL responsibility for a share of DWR's undercollections pursuant to Water Code Section 80104. CMUA distinguishes, however, MDL customers versus the publicly owned utility currently serving such customers. Absent a voluntary agreement with the publicly owned utility, CMUA contends that any such DWR obligation is not the responsibility of the publicly owned utility. CMUA also argues that any obligation of MDL customers should be limited to DWR's historic undercollections. To the extent that the DWR Bond Charge also includes reserves for prospective purchases, CMUA opposes inclusion of such reserves from MDL cost responsibility. CMUA and Merced believe that the "Shortfall Charge" proposed in the Settlement Agreement in the Customer Generation phase of this proceeding offers a fair estimate of the amount to assign to MDL customers.

The proposed "Shortfall Charge" equals 72% of the Bond Charge assessed on bundled customers. The 72% factor is a ratio of (1) a hypothetical bond issuance of $8.6 billion and (2) the approximate actual bond issuance, estimated at $11.95 billion. The derivation of the $8.6 billion hypothetical shortfall as set forth in Appendix C to the Settlement Agreement:

A hypothetical ... bond issue [of $8.6 billion]... would generate sufficient bond proceeds to: finance the Department's undercollections through September 20, 2001; finance the carrying costs of the undercollections from the date of cost incurrence through a hypothetical bond closing date of October 10, 2002; fund bond-related accounts at levels required to comply with the Bond Indenture; fund credit enhancement and issuance costs associated with the bonds. The sizing of the bond issue does not reflect any financing of any of the Department's power purchasing program reserves.³⁷

The DWR Shortfall Charge would cover only DWR's past undercollections and related administrative, financing and carrying costs, but exclude reserve accounts that could be used for DWR forward costs and later reductions to bundled customer Bond Charges.³⁸ As proposed, MDL customers would pay the Shortfall Charge for the full term of the bonds although bundled customers are expected to pay a reduced Bond Charge for the last few years of amortization to the extent operating reserves are used to pay down the bonds. Bundled and DA customers pre-fund deposit and reserve accounts associated with the DWR bond issue and receive the benefits of these funds over the life of the bonds. DL customers, by contrast, would neither pre-fund the reserve accounts nor receive the benefits of those funds during the life of the bonds. Settling Parties characterized the lower upfront charge as "an alternative rate design" in comparison to that applied to bundled and DA load. Merced argues that the "shortfall charge" conforms to AB 117 by charging irrigation district customers only for their "fair share" of DWR's historical electricity purchases, but no more.

Modesto claims that the Rate Agreement exempts its irrigation district customers from any DWR Bond Charges. Modesto notes that while the Rate Agreement permits Bond Charges to be assessed on electric power provided to customers of electric service providers (ESPs), it excludes public agencies such as Modesto from the definition of an ESP. On the basis of the ESP exclusion, Modesto claims customers in its service area are exempt from Bond Charges.

Corona acknowledges that a municipal customer who received DWR-procured power an IOU customer during 2001 could arguably be responsible for a portion of the DWR Bond Charge pursuant to Water Code Section 80104. Corona contends, however, that if municipal customers are subject to a DWR Bond Charge, payment of that charge should be addressed outside of this proceeding in view of the Commission's lack of jurisdiction over municipal utilities. Moreover, Corona does not believe such DWR Bond Charges should be collected by the IOUs. Instead, Corona states that municipal utilities can enter into a direct agreement with DWR that addresses the applicability and amount of any such charge, as well as the mechanism for assessing and delivering the charge.

2. Discussion

We conclude that legal authority exists for the Commission to impose a Bond Charge on MDL customers for their fair share of DWR bond-related costs. Along with broad regulatory powers under the California Constitution and the Public Utilities Code,³⁹ Water Code Section 80110, specifically authorizes us to impose charges on retail customers to recover DWR-related costs, including a Bond Charge. Moreover, AB 117 calls for customers that took bundled IOU service as of February 1, 2001, to bear a "fair share" of DWR costs. Since bundled and DA customers will be paying their share of the DWR Bond Charge, MDL customers that took bundled service on or after this date should likewise share in this obligation. Such sharing promotes bundled customer indifference and avoids cost shifting among customers in accordance with AB 117 and D.02-03-055. Bundled customers would not be indifferent to Bond Charges caused, in part, by customers that had departed the IOU for a municipal utility.

A customer may not escape Bond Charge responsibility merely by departing the IOU to be served by a municipal utility. We agree with CMUA, however, that the Bond Charge obligation applies to the MDL customer who took bundled service on or after February 1, 2001, and not to the municipal utility currently serving such customer. The Bond Charge will be billed and collected pursuant to IOU tariff, and remains an obligation of the MDL customer. The mechanisms required to implement billing and collection of the DWR Bond Charge shall be addressed in a separate implementation phase of this proceeding.

Contrary to the argument of Modesto, the fact that a public agency is exempt from the definition of an ESP does not exempt MDL customers of the public agency from the DWR Bond Charge. While D.02-02-051 applied Bond Charges to ESPs, it did not prohibit application of the Bond Charge to entities other than customers of ESPs.⁴⁰

We also reject Corona's claim that Bond Charges may only be assessed against MDL customers through a separate agreement between the municipality and DWR with no intervention from this Commission. As previously explained, we exercise jurisdiction to impose bond charges through IOU tariffs which is within our authority, and under the statutory authority of AB 117 and related Water Code statutes.

In D.02-11-022, we imposed DWR Bond Charges on DA customers that took bundled service after February 1, 2001. Likewise, D.03-04-030, on cost responsibility for Customer Generation Departing Load, required qualifying load to pay the same per-kWh Bond Charge as bundled customers, and rejected the proposal for a Shortfall Charge that is only 72% of the bundled customers' Bond Charge.

The Shortfall Charge is based on the invalid premise that certain reserves underlying the DWR Bonds can be separated from the historic undercollection. In D.02-11-022, we explained how the reserve accounts relate to the overall DWR Bond financing requirements, resulting in an integrated bond charge. As stated in D. 02-11-022:

"[T]he funding of the various operating reserves at closing was a pre-requisite to actually issuing the bonds. [footnote omitted] The rating agencies insisted on the setting aside of such large sums in these accounts in order to give the bonds favorable credit ratings. Without these large set-asides, the bonds would have had lower ratings, or perhaps could not have been issued at all. An investment grade rating on the DWR Bonds is required by Water Code Section 80130. Lower ratings would have increased the interest on these bonds thus increasing their cost to DA customers. In short, DA customers received a substantial benefit from these set-asides as they enabled the bonds to be issued with favorable ratings." (D.02-11-022, p. 50.)

As explained in D.02-11-022, the hypothetical $8.6 million bond issue underlying the 72% Shortfall Charge does not reflect the financing of the DWR operating reserves. Thus, by excluding these reserve accounts, the Shortfall Charge does not account for the benefits derived from the reserve accounts that apply to all affected customers, including MDL.

Moreover, to the extent these reserves do not become available to reduce future Bond or Power Charges, any purported benefit associated with MDL customers' waiver of any future benefits of the reserves becomes illusory. Given the uncertainty as to how or to what extent the reserves may reduce charges, there is no assurance that bundled customers would ever see offsetting benefits. Accordingly, we decline to adopt the Shortfall Charge, but shall impose a bond charge on MDL customers on the same cost basis as for bundled and DA customers.

As explained in D.02-11-074, DWR was to file by November 8, 2002, its more precise 2003 revenue requirement for bond-related costs with the Commission's Energy Division once the bonds had been placed and DWR had determined actual bond-related charges. The utilities were then to file compliance advice letters to impose a per kWh hour Bond charge on non-exempt bundled consumption delivered on and after November 15, 2002. We herein direct that the Bond Charges filed pursuant to these advice letters be applied to MDL customers in connection with the implementation of this phase of the proceeding.

B. Ongoing DWR Power Charges

In addition to MDL cost responsibility for the DWR Bond Charge, we address MDL responsibility for the ongoing costs that have continued to be incurred under DWR long term contracts. In D.02-11-022, we determined the Bond Charge covered undercollections in DWR costs incurred through September 20, 2001. Thus, a separate component to recover ongoing DWR power costs incurred subsequent to September 20, 2001, is required to make DWR whole for its ongoing costs. Pursuant to D.02-11-022, DA customers bear responsibility for a share of ongoing DWR power costs relating to the above-market commitments in excess surplus off-system sales. We consider herein the extent to which MDL bears a similar responsibility for a share of ongoing above-market DWR power costs.

1. Position of Parties

Municipal parties oppose the imposition of any ongoing DWR power charges on MDL customers. Merced claims that based on traditional cost causation principles, irrigation district customers are not responsible for ongoing DWR power charges. Merced argues that although the record is, at best, "muddy" with respect to what DWR planned for in 2001 in terms of the load that would leave the utilities to take service from irrigation districts, both DWR and PG&E were aware of some irrigation district departing load. PG&E prepared in August 2000 a multi-year forecast of load departing to Modesto and Merced Irrigation Districts which forecast was given to DWR in June 2001.

Modesto and Merced claim that DWR reduced its forecast to take into account customers leaving bundled service for alternative electric suppliers. Specifically, they claim that DWR forecasted a 2% system load reduction in 2001 and a 3% load reduction in 2002 for price response actions, which include leaving bundled service for an alternative electric supplier. (Ex. 109, p. 4; Ex. 112, p. 6.) Merced thus argues that DWR did not procure, or should not have procured, power for some level of DL for reasons other than to take DA service or to install self-generation, such as to take service from an irrigation district.

Merced witness Krause testified that between the time it began providing retail electric distribution service in 1996, and the beginning of 2001 when DWR forecasts began to be prepared, its customer count had grown to over 200, and it was serving connected peak load in the range of 40 to 60 MW. Merced argues that to the extent that PG&E or DWR failed to account for movement of such load, customers leaving PG&E to take service from an ID may be burdened with costs that should not be attributable to them.

CMUA argues that even to the extent Navigant/DWR did not make a separate MDL adjustment for price elasticity it was because the IOUs separately considered and assumed (or ought to have assumed) some level of MDL in the forecasts handed off to Navigant. CMUA thus claims that it would be unreasonable for the IOUs to argue that DWR had actually "incurred costs" for this level of MDL. While CMUA may disagree with the IOUs concerning the magnitude of MDL that ought to be exempted, CMUA argues that the IOUs ought to jointly agree that some level of Municipal Departing Load should be exempted from DWR power charges.

WPA argues that its customers should not be required to pay any DWR ongoing costs because its customers' departure from IOU service was foreseeable at the time PG&E provided its forecast load data to DWR for purposes of procurement planning. WPA is a municipal agency formed to acquire from PG&E certain electric distribution and transmission facilities. The load that WPA will serve is departing PG&E's system pursuant to PG&E's sale of these facilities to Turlock Irrigation District. PG&E's witness testified, however, that PG&E did not specifically account for the departure of WPA load when it prepared the forecast data upon which DWR relied in making its procurement decisions. PG&E believes that WPA load is properly included in forecasts underlying MDL cost responsibility because finalization of the WPA agreement still remains unresolved. WPA argues that PG&E's inclusion of WPA load is imprudent in view of the fact that PG&E had contracted with the Turlock Irrigation District to turn this load over to WPA in the near future.

ORA disputes claims that DWR did not procure power on behalf of MDL customers, and notes that neither Merced nor Modesto were able to cite to the record for the claim that DWR reduced its forecast to take into account departing municipal load.⁴¹ TURN likewise argues that DWR's forecast load reduction in 2001 and 2002 merely reflected price elasticity in response to conservation, not the complete departure of certain customers from the system. With respect to the argument that PG&E, Navigant, or DWR should have accounted for departing muni load anyway, ORA notes that an expert in the area of forecasting thought the future of departing muni load was lessened due to wholesale market problems in 2001 and even Westside's contractual commitment to serve departing muni load was dependent upon unsure contingencies.

The IOUs oppose any exemption of MDL from DWR ongoing power charges, and deny that DWR took into account any anticipated departures of customers to municipalities in making its forecasts. SDG&E argues that the DWR surcharge should apply to each departing group of customers that would otherwise bypass DWR costs incurred on their behalf. SDG&E argues that the benefit of any considerations in the DWR forecast for demand elasticities and conservation should reasonably accrue to all bundled customers and not to municipals.

SCE argues that DWR actual procurement is what matters here, not what it should have procured. SCE contends that the Commission must implement charges to recover DWR's revenue requirement, and cannot disallow costs to correct for what DWR should have done. SCE argues that to the extent that these costs are recovered, all customers, including MDL, must participate to avoid cost shifting to bundled service customers.

2. Discussion

We conclude that MDL customers should be held responsible for a fair share of ongoing DWR power costs in order to avoid cost shifting in compliance with AB 117. We shall therefore impose a component for DWR power costs patterned after the DA CRS which covers the period since September 21, 2001. During this period, DWR has been collecting its revenue requirement through bundled customer proceeds based on power charges that were implemented in D.02-02-052 and DA CRS methodology implemented pursuant to D.02-11-022. MDL customers have not paid anything since their departure to municipal service to cover their share of past costs incurred by DWR during this period. Accordingly, a separate element must be quantified to assess the requisite share of costs on MDL customers covering their responsibility for this period. We discuss further implementation measures in this regard in Section V.C. below.

We conclude that DWR incorporated no explicit reduction in the load forecasts underlying its procurement program to reflect departure of load to municipal service. While Navigant assumed annual capacity reductions from 2001 through 2011 in Distributed Generation, Navigant's witness had no estimate of how much departing municipal load there would be over the same time.⁴² Navigant witness McDonald testified that DWR assumed no load reductions associated with municipalization efforts.⁴³ McDonald stated: "We also know how difficult it is to do things like municipalize an area, long lead times that it takes, and we know that there are some other - so we did not see that that was something that we really needed to factor into the forecast." (DWR/McDonald, RT Vol. 12, p. 1499 (emphasis added).)

Contrary to the arguments of Merced, although DWR included a certain amount of price elasticity in its forecast, we find no connection between that adjustment and MDL.⁴⁴ Navigant witness McMahon testified that, "the price-elasticity adjustment [reflected in DWR's revenue requirement] is capturing only reductions in usage, and that departing load in the form of distributed generation and direct access is modeled separately."⁴⁵ Neither Merced's nor Modesto's witnesses point to any specific evidence to show that the two-percent system load reductions for 2001 and three-percent system load reductions in 2002, which were included for price response action, represented MDL. We find no evidence of any explicit level of MDL the IOUs expected or that it was ever included in DWR's load forecast. Witness McDonald's testimony shows that Navigant did not consider MDL when it presented its forecasts to DWR. All bundled customers took energy from the DWR contracts, and we find no evidence that DWR actually contracted for less energy procurement based on the belief the current or future load would depart to publicly owned utilities.

CMUA claims the IOUs independently anticipated a certain level of MDL,⁴⁶ and on that basis, some exclusion is warranted from ongoing DWR power charges. Although IOU witnesses agreed that some implicit effects of municipalization could be embedded within load forecasts, they had no specific knowledge of departing load assumptions relating to municipalization. CMUA failed to offer any specific adjustments to IOU load forecasts representing exclusion or adjustment for MDL. To the extent MDL assumptions may be implicit in the IOU forecasts that were used by DWR, those assumptions would have reduced the aggregate contract commitments made and all affected customers (including MDL) thereby benefit. Given the lack of a record as to any specific load forecast adjustment for MDL, however, we find no basis to adopt a specific CRS exclusion expressly for MDL customers.

Moreover, a specific DWR exclusion applied to MDL could create a price disparity between the IOUs and municipal utilities that could significantly accelerate the rate of municipalization. As customers migrated to the municipality to escape DWR charges, the result could be a much greater level of MDL than was implied in the IOUs' load forecasts. The result would lead to cost shifting and conflict with the stated intent of AB 117. To guard against the risk of such a result, MDL customers should bear responsibility for DWR power charges.

We find unpersuasive CMUA's argument claiming that it is inequitable to exclude as certain customer generation load from DWR's ongoing costs, (as contemplated in the proposed Customer Generation Settlement Agreement) while charging MDL. This argument fails to recognize the difference between the treatment of Customer Generation versus Municipal Load in DWR's forecasting and contracting practices. While DWR actually forecasted a specific amount of departing load associated with new customer generation, it made no corresponding MDL forecast.⁴⁷ The amount of customer generation departing load proposed to be exempt from the CRS, by contrast, is directly tied to this DWR forecast.⁴⁸

To the extent a municipality acquires customers that an IOU would otherwise have served, the municipality reduces the amount of IOU load for which DWR incurred long-term contract expenses and commitments. Unless appropriate surcharges are imposed, this departure would enable these customers now served by the municipal utility to escape their fair share of costs incurred on their behalf and will result in higher DWR costs being assigned to all remaining customers. Therefore, since DWR incurred costs for customers' load that might prospectively be served by a municipal and made no provision for municipals taking load from an IOU, MDL customers must bear a share of DWR ongoing power charges in order to avoid cost shifting to bundled customers.

We decline to exempt WPA customer load from DWR charges. In support of its request for a special exemption, WPA claims that "[c]learly, DWR did not enter into any long term contracts with the expectation that it would need to purchase power for the load departing to TID/WPA."⁴⁹ WPA provides no evidence, however, to support this assertion.

Because the transaction contemplated with WPA was unresolved at the time that DWR forecasts were made, PG&E reasonably assumed in its forecast that customers in the Westside Zone would continue to be served by the IOU.⁵⁰ The transfer of the customer load to Westside is contingent upon final approval by the Commission and/or the FERC, neither of which has occurred. (Weis/Westside, RT Vol. 14, p. 1716.) Although TID/WPA negotiated a Memorandum of Understanding (MOU) with PG&E on August 31, 2000, the transaction was unresolved prior to, and even after, passage of AB 1X. At the time briefs were filed in this proceeding, only two of the four conditions contemplated in the MOU had thus far been met.⁵¹

Although the MOU was signed in August 2000, the parties did not reach sign a final purchase and sale agreement until December 18, 2001.⁵² As described in the application for the proposed sale, Section 4.3 of the agreement "provides that TID will pay any other non-bypassable charges owed by Westside Zone consumers adopted by the Commission or by the Legislature prior to the Closing Date, such as any charges for Department of Water Resources costs or prior uncollected excess power purchase costs."⁵³

In D.03-04-032, dated April 3, 2003 we subsequently approved the transfer of facilities by PG&E to TID. We required in that decision that departing customers be responsible for any CRS established after the closing date of the transaction to the extent required by state law or Commission decision.

Because customers within the Westside Zone continued to receive DWR power since January 17, 2001, and due to uncertainties regarding the pending sale, we reject WPA's claim that PG&E (and DWR) should not have anticipated continuing to serve customers in the Westside Zone. Thus, we decline to grant WPA customers an exemption from DWR's bond and power charges, but shall require them to share DWR cost responsibility on the same basis as other MDL customers.

C. Competition Transition Charge

Another component of cost responsibility at issue for MDL customers is the "competition transition charge" (CTC). Although CTC was originally envisioned as a byproduct of an industry restructuring program to provide for an "orderly" transition to a competitive environment pursuant to legislative enacted in AB 1890,⁵⁴ that concept no longer retains its original meaning. Under AB 6X, URG portfolios are once again under cost-of-service regulation. As we concluded in D.02-11-022, however, nothing in AB 6X affects the fact that customers, including DL, must pay their applicable share of above-market qualifying facilities (QF) and purchased power costs.

Section 369 authorized the Commission to establish a mechanism for recovery of transition costs as "referred to in Sections 367, 368, 375, 376, and subject to the conditions in Sections 371 and 374, inclusive, from all existing and future consumers in the [utility's] service territory ...." Section 368(a) prescribed that electric rates would remain frozen at the June 10, 1996 levels, through March 31, 2002, at the latest, except for residential and small commercial customer rates which were reduced by 10%. These frozen rates, along with a residual component of rates specifically delineated as the CTC, provided an opportunity for the utilities to recover these transition costs.

Transition costs were to sunset on March 31, 2002. (See §§ 367 et seq.) The Legislature allowed for certain exceptions to this sunset date. (See §§ 367(a) and 376.) D.00-06-034 (in A.99-01-016) adopted a methodology for allocating ongoing transition costs (i.e., "tail" CTC) after the end of the AB 1890 rate freeze, but did not address how such amounts were to be calculated. The decision directed PG&E to implement CTC through its Phase 2 general rate case (A.99-03-014) and SCE through A.00-01-009. Since these two proceedings have been suspended or otherwise terminated, the ongoing CTC applicable to DL customer is being addressed in this proceeding. In D.02-11-022, we adopted a proxy value of 4.3 cents/kWh for purposes of computing the above-market component of Section 367 costs subject to ongoing or tail CTC treatment.

1. Parties' Position

CMUA acknowledges that Section 369 makes tail CTC applicable to MDL, but denies that tail CTC is applicable to New Municipal Customer Load. A further discussion of the treatment of new municipal load is set forth in Section V.A. herein. CMUA claims that absent a voluntary agreement by the publicly owned utility, any CTC obligation does not become an obligation of the publicly owned utility.⁵⁵

CMUA argues that the Commission does not have discretion, as it does with other customers, including DA, to recover costs other than "transition costs referred to in Sections 367, 368, 375 and 376..." CMUA argues, the recovery of generation-related transition costs (except for tail CTC) was bounded by time and has now come to an end: "...uneconomic costs shall be recovered from all customers on a nonbypassable basis...provided that, the recovery shall not extend beyond December 31, 2001, except [for "tail CTC"]."⁵⁶ CMUA believes that it would be inappropriate for the Commission to attempt to use its authority under Section 369 to "redefine" tail CTC in an effort extend the reach of these costs to Municipal Departing Load.

CMUA opposes inclusion of Western Area Power Administration (WAPA) costs within the scope of PG&E's tail CTC recoverable from MDL customers. CMUA asserts that the costs associated with the power sale to WAPA do not fit within the categories set forth in Section 369 and that only pre-existing power purchase obligations, not power sale obligations, are statutorily allowed for recovery from municipal departing load.

CMUA contends that under Section 367, December 20, 1995, is the date of reference for any qualifying power purchase agreement. Assuming PG&E's transaction with DWR can rightfully be considered a "purchase" (which CMUA believes is debatable), CMUA nevertheless believes it is denied cost recovery from MDL since the "agreement" to purchase occurred after December 20, 1995.

Merced argues that the applicability of tail CTC should be consistent with Section 374(a).⁵⁷ Section 374 expired on March 31, 2002 and is inapplicable. Modesto argues that transition cost recovery expired on December 31, 2001.⁵⁸ It is not clear what legislation Modesto is referring to. CTC collection continued through March 31, 2002, and as provided in Section 367, tail-CTC continues after March 31, 2002.

Merced agrees that, pursuant to Sections 367 and 369, irrigation district departing load is subject to tail CTC.⁵⁹ For purposes of this proceeding, Merced defines tail CTC based upon Section 367, and thus limited to the following costs: (1) employee-related transition costs (through December 31, 2006); (2) existing power purchase contract obligations (through the duration of the contract); (3) nuclear incremental cost incentive plans for San Onofre (through December 31, 2003); and (4) fixed transition amounts, as applicable. Merced opposes any effort to expand tail CTCs beyond these statutorily authorized costs.

PG&E charges a tail CTC component to MDL customers as part of its approved tariff, and proposes to continue this tail CTC. ⁶⁰ PG&E disputes CMUA's claim that WAPA transactions do not properly conform to CTC eligibility requirements. PG&E notes that under Section 840(f), IOUs may include uneconomic costs of power purchase contracts within the definition of transition costs. Section 367(a) directs the Commission to identify and determine categories of transition costs, including those identified in Section 840(f), for collection on a nonbypassable basis from all customers by December 31, 2001. Section 367(a) further provides that collection of certain transition costs - or "tail CTC" - could extend beyond December 31, 2001. Included among those costs eligible for "tail CTC" treatment are power purchase obligations.⁶¹

PG&E contends that the terms of the PG&E/WAPA contract fit within the eligible transition cost definition articulated by the Commission in D.97-11-074, and that CMUA's objection to the inclusion of these costs in tail CTC should be rejected.

SDG&E does not recommend any change from its existing application of CTC to MDL customers through its approved Electric Department Tariff Rule 23. SDG&E's CTC is collected in a prescribed manner that reflects the fact that SDG&E has ended its rate freeze. SDG&E argues that leaving the application of CTC to DL customers unchanged and adopting a DWR bond and power charge will not result in any double billing of costs.

In its initial testimony, SCE proposed that the ongoing CTC component be based on costs associated with SCE's URG portfolio, as well as any other costs identified in Section 367, in order to recognize passage of AB6X. AB6X required SCE to retain its remaining generation assets and the Commission included SCE's Qualifying Facility and Interutility Contract costs in the adopted ratemaking for URG costs. SCE is amenable, however, to basing the calculation of tail CTC on a strict interpretation of Section 367, as proposed by CMUA.

2. Discussion

We shall direct the IOUs continue to charge tail CTC to MDL pursuant to their approved tariffs. We address the applicability of tail CTC to new municipal load in Section V.A. herein.

In D.96-04-054,⁶² we determined that CTC should be borne by all customers, including departing load customers, in rough proportion to the benefits they received. The fact that some departing load customers subsequently took service from a publicly owned municipality does not relieve them of responsibility for CTC costs as determined by D.96-04-054.

Moreover, the provisions of AB 1890 expressly provide for the recovery of CTC from DL customers, including those that migrate to municipal utilities. The need to address whether the Commission had exceeded its authority in D.96-04-054 was made moot by the subsequent passage of AB 1890, as noted in D. 97-11-031.⁶³

Section 367 provides for the recovery of CTC, and Section 369 specifies that the obligation to pay ongoing CTC cannot be avoided by "the formation of a publicly owned electrical corporation on or after December 20, 1995." The Commission's authority to impose such charges thus stems from the prior customers' status as bundled customers of an IOU, and does not presume any jurisdiction over the regulation of rates, charges or services offered by a publicly owned municipal utility. The costs that are relevant in this proceeding to the departing load customers relate only to IOU service received by these customers over which the Commission exercises jurisdiction, and not the ongoing service they are currently receiving from a publicly-owned utility.⁶⁴

We agree with PG&E that WAPA costs are properly included within CTC applied to MDL. This finding is consistent with D.02-11-022 in which we determined that WAPA contract costs were a CTC component applicable to DA customers. (See D.02-11-022, p. 137.) This treatment is also consistent with D.97-11-074 in which the Commission stated:

PU Code §367 affirms the Preferred Policy Decision finding that the utilities are authorized to collect the ongoing transition costs resulting from the difference between contract prices with QFs and the Power Exchange market-clearing price.⁶⁵

This description is thus consistent with the inclusion of WAPA costs in the tail CTC.

Later in the same decision, we equated QF contracts to the utilities' power purchase contracts with other utilities, irrigations districts or water agencies:

PG&E . . . [has] various purchased power contracts with other utilities, irrigation districts, or water agencies. Similar to the treatment of QF contracts, both AB 1890 and the Preferred Policy Decision provided for the recovery of the difference between the actual payments under those contracts and the costs of comparable energy purchases from the Power Exchange.⁶⁶

D. Recovery of Costs in SCE's PROACT Through the HPC

D.02-07-032 authorized SCE to establish a "Historical Procurement Charge" (HPC) in the matter of A.98-07-003. The HPC provides recovery of the balance in SCE's Procurement Related Obligation Account (PROACT). In D.02-07-032, as modified by D.03-02-035, SCE was authorized to apply the HPC to DA customers by reducing the DA customers' generation credit by 2.7 cents/kWh until the effective date of a Commission decision implementing a DA CRS in the instant rulemaking (R.02-01-011). This reduction in the DA surcharge credit was intended to provide for equivalent contributions between bundled and DA customers for the recovery of SCE's PROACT balance.

Because DL customers affected by SCE's HPC proposal did not receive adequate notice at the time, SCE agreed to withdraw its testimony in the A.98-07-003 proceeding regarding application of the HPC to DL customers. SCE has now presented its proposal for HPC recovery by DL customers as part of its testimony in this proceeding.

1. Parties' Positions

SCE proposes that responsibility for the HPC apply to MDL based on whether the load existed in SCE's service territory as of March 29, 2002, the date of the ALJ ruling indicating that DL customers may bear responsibility for HPC costs. For DL customers that previously took DA service, SCE proposes that the customer pay the HPC adopted by the Commission in D.02-07-032 for its departed load.

SCE proposes that the Commission adopt the factors that SCE proposed in A.98-08-003 for DL customers that were on bundled service. SCE's bundled customers have been making payments toward recovery of the PROACT balance since June 3, 2001 when Commission-adopted surcharges were included in customers' bills. The proposed HPC will identify the relative contribution each customer group made toward the unrecovered procurement costs in the PROACT. SCE proposes a two-year amortization period, consistent with the expected time needed for the recovery of the PROACT balance from bundled customers.

SCE observes that a customer could switch from DA to bundled service just prior to the time that load departs in order to reduce its HPC obligation. SCE thus proposes that the proper rules be established in Schedule DL-NBC to eliminate such gaming opportunities. SCE proposes to address these issues in an advice letter implementing this decision.

PG&E proposes to defer a determination as to whether it is appropriate to impose a charge on all customers for PG&E's unrecovered costs associated with the energy crisis to the appropriate proceeding.⁶⁷

As previously noted above, the municipal parties generally oppose imposition of any HPC on MDL customers. Since the area where Merced provides electric services is located in PG&E's territory, Merced focuses its attention solely on PG&E's undercollection proposal. While Merced is prepared to address the issue of any surcharges related to PG&E's undercollection in a different proceeding, Merced opposes any assessment of such a surcharge on irrigation district departing load customers. Merced argues that, under AB 1890, PG&E knowingly took the risk that power costs might exceed sales prices, and should not now be allowed to shift that risk to its customers.

2. Discussion

Consistent with our imposition of an HPC to bundled and DA customers, we hereby correspondingly adopt SCE's proposal to apply an HPC to MDL customers. Because SCE is unable to identify the amount and identity of MDL at this point, it is not possible to determine a fixed HPC revenue requirement for MDL. Accordingly, we accept SCE's proposal to apply its proposed HPC factors from A.98-11-038 which were intended to reflect each customer group's relative contribution to the PROACT balance.

As SCE explains, because its costs and DA credit exceeded revenues recovered during most of the period from June 2000 through September 2001, the net result increased SCE's PROACT liabilities. For purposes of determining each customer group's HPC factor, SCE calculated the annual revenue requirement of the PROACT balance allocated among customer groups based on the ratio of each group's consumption relative to SCE's total system. This calculation was set forth in Table V-1 of Exhibit 76, and is reproduced in Appendix A of this order.

We shall also adopt SCE's proposal to apply to the HPC to MDL customers that departed the IOU on or after March 29, 2002. On that date, the ALJ ruling was issued, serving notice that DL customers faced the potential for having to pay an HPC. We shall adopt SCE's proposed two-year amortization period for HPC for MDL customers, consistent with the expected time needed to recover its PROACT balance from bundled customers.

Because PG&E has not yet placed any proposal before us concerning the treatment of its undercollection, we make no findings here concerning the ultimate disposition of any proposal that may subsequently be filed. The treatment of SCE's HPC is not intended to prejudge or set a precedent for how we may consider or dispose of cost responsibility relating to any PG&E undercollection.