VIII. Review of Charges to be Imposed on Departing Load Customers

A. Recovery of DWR Bond Charges

1. Background

Current bundled customers, like DL customers who received bundled service subsequent to January 17, 2001, did not pay fully for the DWR's procurement costs incurred during 2001. In order to reduce the immediate rate impact, DWR anticipated financing a part of the costs incurred during 2001 at the highest rate levels by issuing bonds. Under AB 1X, the revenue shortfall for the historic period was to be financed through the sale of State of California Bonds. In D.02-02-051, the Commission adopted a "Rate Agreement" governing the terms by which the Bonds would be administered. As stated in D.02-02-051:

Under the Act, the Commission has an obligation to impose charges on electric customers that are sufficient to compensate DWR for its costs under the Act, including procuring and delivering power, and paying bond principal and interest.

The adopted Rate Agreement establishes two streams of revenues. One stream of revenues will come from Bond Charges imposed on electric customers, and is designed to pay for bond-related costs. The second stream of revenues will come from Power Charges imposed on electric customers who buy power from DWR, and is designed to pay for the costs that DWR incurs to procure and deliver power. Both streams of revenue are necessary for DWR to issue bonds with investment-grade ratings.

In D.02-11-022, we directed that a Bond Charge be imposed on DA customers (other than those that have remained continuously on DA service) on a cents/kilowatts-hour (kWh) basis equivalent to that imposed on bundled customers. The actual determination of the revenue requirement and per-customer bond charge, however, was to be implemented in A.00-11-038 et al. (the "Bond Charge" phase). .³⁴ On October 24, 2002, D. 02-10-063 was issued, adopting a methodology for developing a DWR Bond Charges.

D. 02-10-063 was further amended on rehearing by D. 02-11-074. As explained in that order, DWR was to file by November 8, 2002, its more precise 2003 bond revenue requirement for bond-related costs with the Energy Division once the bonds have been placed and DWR has determined its actual bond-related charges. The utilities were to make compliance advice letter filings within 5 days following DWR's updated submission to impose a per kWh hour Bond charge on non-exempt bundled consumption delivered on and after November 15, 2002. SDGE, SCE, and PG&E were to calculate a uniform per kWh charge by dividing the more precise 2003 bond revenue requirement by 106,222 GWh.. 35

The determination of whether, or to what extent, Customer Generation load should pay for Bond-related costs was deferred to the instant proceeding. Pending the implementation of any actual Bond Charge recovery, we made provision in D.02-10-063 for the tracking of both DA and DL cost responsibility, and ordered each of the utilities to create a Bond-Charge Balancing Account (BCBA) for that purpose..

Once the instant decision addressing the applicability of Bond Charges to DL customers becomes final and unappealable, the actual Bond Charge component of the CRS will be implemented for Customer Generation load, on the terms as set forth in this order, as discussed below.

2. Parties' Positions Prior to the Settlement

Prior to the settlement, two opposing views generally emerged concerning applicability of the Bond Charge. Parties representing utility and bundled customer interests (i.e., ORA and TURN) contended that DL should pay all charges related to the DWR bonds on the same basis as bundled customers.36 Other parties proposed alternatives to a one-size-fits-all bond charge.37

Parties representing Customer Generation interests advocated an opposing view. A number of parties claimed the Commission lacks authority to impose any charge related to the DWR bonds on DL.³⁸ Parties also argued that imposing Bond Charges would run counter to various state and federal mandates to encourage the development of preferred forms of alternative generation, and that there should be exemptions from DWR's past costs for small clean distributed generation,³⁹ for distributed solar generation,⁴⁰ and for certain other types of customer generation.⁴¹

3. Discussion

The application of a uniform bond charge to Customer Generation load is consistent with D.02-02-051 in which the principles for application of the Bond Charge were articulated. In that order, we stated:

"The Act does not require Bond-Related Costs to be recovered through charges that are imposed only on the power that is sold by DWR. Nor does the Act require the use of a particular ratemaking method to recover DWR's Bond-Related Costs or Department Costs. Therefore, the Commission may use its broad authority under Water Code § 80110 and Pub. Util. Code § 451 and § 701 to devise and implement the separate Power Charges and Bond Charges set forth in the Rate Agreement.

"At the time the Act was passed into law, it was unknown how the energy crisis would unfold or how long DWR might be selling power, which suggests that the Legislature intended to provide DWR and the Commission with great flexibility in the Act to devise a means to recover DWR's revenue requirement. . . " (D.02-2-051)

On the other hand, the recovery methodology proposed in the Settlement differs from the approach that we have adopted for applying Bond Charges to bundled and DA customers. Instead of paying a full pro rata share of the full bond chare, Customer Generation load would only pay 72% of the requirements otherwise assessed against bundled and DA load.

The Shortfall Charge covers the administrative, financing, and reserve costs associated only with the historic undercollection, but the remaining reserve and deposit accounts making up the total bond proceeds. Settling Parties argue that to compensate for the upfront discount, Customer Generation would not receive the future benefit from the funds in those reserve accounts to the extent they are used to reduce future power charges or to shorten the term of the Bond Charge. Settling Parties argue that the lower upfront charge is merely an alternative rate design in comparison to that applied to bundled and DA load. Settling Parties portray the proposed treatment merely as a difference in the timing of charges, rather than as any absolute advantage over time.

We find this justification unconvincing. Further, as we have declined to adopt the proposed settlement agreement, we find that all departing load customers shall pay 100% of the bond charge.

As noted by SDG&E, it is not clear to what extent the bond reserves would be released at some future date to pay down the Bond obligation or to reduce future ongoing power charges. Reference Exhibit 1a in the Bond Charge Proceeding described what will happen to a large portion of these funds. The majority of the initial deposit to the Operating Account consists of an $850 million increase to the Minimum Operating Expense Available Balance. This additional cushion in the Operating Account is only required so long as DWR continues to procure the Residual Net Short. As soon as that responsibility has been transferred to the investor-owned utilities, the Minimum Operating Expense Available Balance requirement will be reduced by $850 million (even if DWR continues to be responsible for long term contracts). At that time, the freed up funds can be used to "either retire the additional debt issued to fund the higher account balance or can be used for more immediate ratepayer relief. The Commission, after consultation with the Department, will be responsible for determining the use of the excess amounts.⁴²" If the funds are used to retire debt, all customers responsible for paying Bond Charges will benefit. If the funds are used for more immediate ratepayer relief, the extent to which customers may benefit will depend on whether that relief comes in the form of a reduction to Bond Charges or Power Charges, or both, an issue that has not yet been decided.

Moreover, the Operating Reserve referenced in Exhibit 106 of the Bond Charge Proceeding is set aside to cover the contingency that the Operating Account may not be sufficient to fund all operating costs. Absent this contingency, there is no certainty that the sums in the Operating Reserve Account will ever be used to fund DWR's ongoing power purchases. To the extent that these reserves do not become available to reduce future Bond or Power Charges, the purported benefit associated with Customer Generation waiver of any right to the future benefits of any reserves becomes illusory. Given the uncertainty as to how or to what extent current reserves may reduce charges, there is no assurance that bundled customers would ever see offsetting benefits in relation to the upfront benefit accorded Customer Generation through the 28% discount. Customer Generation could thereby gain an unfair advantage in relation bundled customers if they were granted a front-loaded 28% discount excluding these reserves.

Moreover, we disagree that the funding of reserve accounts for ongoing costs represents any improper "commingling" with historic shortfall costs. In D.02-11-022, we previously explained how the reserve accounts relate to the overall DWR Bond financing requirements. As stated by DWR in Exhibit 3, the hypothetical $8.6 million bond issue "does not reflect the financing of any of the Department's power purchasing program reserves, the funding of which will be a condition of the rating agencies in order to secure the Department's desired level of investment grade ratings on the bonds."

Thus, the funding of the various operating reserves at closing is a pre-requisite to actually issuing the bonds. 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, customers receive a substantial benefit from these set-asides as they will enable the bonds to be issued with favorable ratings, thereby lowering interest charges. Thus, the cost of funding these set-asides form an integral part of the favorable financing terms applicable to the historic shortfall. By excluding the funding of these reserve accounts in the derivation of the 72% ratio, the Shortfall Charge does not account for any of the benefits realized by all affected customers, including Customer Generation, derived from the reserve accounts.

Moreover, as noted by SDG&E, assuming the reserve funds were used to retire the bonds early, the Settlement fails to explain what regulatory treatment would be applied to revenues collected from Customer Generation thereafter, or how the applicable shortfall charge would be determined when there is no remaining Bond Charge in place from which a 72% ratio can be applied.

Because we have found the bond charge to be an integrated whole, it would be improper and unfair to approve any discounted Shortfall charge that assumes such reserves can be severed. We find that this distinction is not supported by the record, nor is it consistent with the approach applied to DA customers in D. 02-11-022. Thus, we find persuasive the arguments presented by ORA and SDG&E that the Settlement does not meet the criteria for approval to the extent that it would impose a discounted Shortfall charge.

We likewise find no basis in the record of this proceeding to apply a 28% discount to DL customers on the basis of legislative mandates to promote development of various forms of alternative generation. We recognize that differences exist in certain characteristics of Customer Generation compared to DA. Whereas the Legislature has suspended DA, it has not suspended Customer Generation. In fact, parties have cited various statutes indicating legislative intent to encourage the growth of new Customer Generation. Yet, there is no basis in this proceeding to quantify any explicit dollar valuation attributable to societal benefits derived from Customer Generation.

As we noted previously, while we acknowledge that there is nothing in the record to quantify societal benefits for customer generation, there is a strong basis in Legislative intent to differentiate between departing load and super-clean & low-emission distributed generation.

We find no record here, however, to conclude that any potential benefits to be realized from deployment of Customer Generation necessarily relate in monetary terms to the 28% discount that would result from approving the Settlement's Shortfall Charge. We therefore cannot conclude that the Settlement is reasonable in light of the whole record in assigning a 28% discount to the otherwise applicable bond charge assigned to Customer Generation.

As noted by SCE witness Collette, specific issues relating to any valuation system that could be employed to assign value for the benefits that Customer Generation allegedly confers is pending before the Commission as part of R.99-10-025 (Rulemaking regarding Distributed Generation). The determination of incentives or subsidies, if any, that should apply for deployment and development of certain Customer Generation technologies is more appropriately addressed in the R.99-10-025 proceeding.

Based solely on the record in this proceeding, however, we find no basis to conclude that the Settlement is reasonable in applying a 28% discount off the Bond Charge reasonably reflects the dollar value of those benefits. Possible adoption of subsidies to encourage deployment or to recognize benefits from preferred alternative generation technologies may be addressed further in R.99-10-025.

We thus conclude that based on the record, Customer Generation should bear responsibility for the full Bond Charge, including associated reserve accounts, on the same basis as bundled and DA customers

B. DWR Ongoing Power Costs

1. Positions of Parties Prior to the Settlement

In its case in chief, PG&E and SCE proposed that Customer Generation loads that departed from utility service after January 17, 2001, when DWR entered the procurement market on behalf of utility customers, should not be allowed to escape their fair share of DWR's ongoing power costs. PG&E argues that all customers on PG&E's system, as of January 17, 2001, benefited from DWR's role as "default provider." PG&E and SCE do not propose to apply any DWR charges to customers that departed its system prior to January 17, 2001, since such customers never benefited from DWR-procured power.

SDG&E does not propose to charge any Customer Generation load for DWR-related ongoing power charges. SDG&E does not believe that assessing such charges on such customers is warranted, arguing that DWR did not incur costs on behalf of such customers, but assumed they would procure their power independently of DWR through self-generation.

TURN proposed that Customer Generation should pay for ongoing DWR power charges, with the exception of eligible for standby charge exemptions (net metered customers plus new Customer Generation under five MW installed before the specific dates established by legislation). TURN believes that this limited exemption would avoid double counting of charges that are already collected in those standby charges.

ORA proposes that all Customer Generation load should bear a share of the ongoing DWR power charge. ORA recommends, for now, adoption of an identical surcharge applicable both to direct access and departing load based on Navigant's modeling of the cost-impact of last year's return of a substantial load from bundled service to direct access. Any surcharge true up in 2003 or 2004 could then capture incremental cost impacts of departing load. ORA anticipates the three IOU's will actually implement a surcharge related to departing load via existing rate schedules.⁴³

We agree with PG&E that customers taking bundled service as of January 17, 2001, benefited from DWR's role as "default provider" and should not avoid paying their fair share of ongoing DWR power costs.

We agree with TURN that, except for customers eligible for standby charges (net metered customers plus new Customer Generation under five MW installed before the specific dates established by legislation), departing load customers should pay for ongoing DWR power costs.

As we explained above in Section IV, we exempt 200 MW of super-clean distributed generation as defined in Pub. Util. Code § 353.2 (a) from the ongoing DWR power costs.

C. Tail CTCs

1. Background

The Settlement Agreement also addresses the recovery of certain utility-related above-market generation charges, commonly referred to as "tail" CTC applicable to DL served by Customer Generation. ." CTC was originally envisioned as a byproduct of a industry restructuring program to provide for a competitive environment pursuant to legislative enacted in AB 1890. As originally envisioned, AB 1890 was to provide for an "orderly" transition to a competitive generation market which would be completed by March 2002. (Pub. Util. Code § 330.)⁴⁴

Pub. Util. Code § 369 provides that "[t]he commission shall establish an effective mechanism that ensures recovery of transition costs 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 . . . Pub. Util. Code § 368(a) prescribed that electric rates would remain fixed at the June 10, 1996 levels, 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, allowed the utilities to accrue the revenues to collect "transition costs."

D.00-06-034 in the Post-Transition Period Ratemaking Proceeding (A.99-01-016) adopted a methodology for allocating ongoing transition costs 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,⁴⁵ the determination of ongoing CTC applicable to DL customers remains to be addressed in this proceeding.

2. Parties' Positions - Pre-Settlement

Certain parties opposed any charge to DL customers for ongoing above-market utility portfolio costs.⁴⁶ Various parties representing Customer Generation interests argue that while AB 1890 gave the Commission limited authority to impose certain surcharges on direct access customers, it specifically exempted onsite customer generation from these charges. (Pub. Util. Code § 372.) In addition, even where AB 1890 gave the Commission authority to impose surcharges, they claim that most were subject to a statutory sunset date of December 31, 2001.

CLECA argues that "it does not make sense" that utility tail CTC should continue to apply to departing load, on the premise that "the entire concept of tail CTC has lost any meaning in the wake of the Legislature's passage of AB 6X and the return to cost-of-service ratemaking for utility generation.⁴⁷" Other parties argued in favor of similar exemptions from "tail" CTCs.⁴⁸

The utilities proposed, in contrast, that some measure of ongoing utility portfolio costs be imposed on DL.⁴⁹ PG&E proposed the continuation of the "tail CTC" under AB 1890.⁵⁰ SCE proposed that the Commission "establish a nonbypassable charge to recover the above-market costs of SCE's portfolio of retained generation and energy contracts." Unlike the "tail CTC" in AB 1890, SCE's proposed measure would have been unlimited both in term and in the resources that could be included in the ongoing charge. SCE argues that the "tail CTC", a more limited measure of ongoing utility portfolio costs, combined with a continuing cogeneration exemption, represents a reasonable compromise of positions in the interests of bundled ratepayers, the utilities and DL customers. SDG&E is uniquely situated with respect to its recovery of CTC because it has ended its rate freeze. SDG&E argues that the Commission, in this proceeding, should expressly authorize the continued collection of SDG&E's CTC pursuant to existing tariff.

3. Discussion

Although parties disagree in principle over the interpretation of AB 1890, under which the concept of "tail CTC" originated, and its implications for DL cost responsibility, the Settlement represents a reasonable disposition of their differences. We conclude that the Settlement's proposed imposition of tail CTC on Customer Generation load assigns them a fair share of costs, and is reasonable in light of Commission policy and applicable law. We have previously addressed the applicability of tail CTC to DA customers in D.02-11-022. Consistent with that order, we conclude that legal authority exists for imposing a share of above-market CTC-related costs on Customer Generation load.

We recognize that the concept of "transition costs," as originally contemplated in AB 1890 no longer retains its initial meaning. When the Commission addressed "tail" CTC in its second Post Transition Ratemaking (PTR) order D.00-06-034, it envisioned a largely unregulated generation market after the end of the rate freeze. Section 367 envisioned that the utilities would sell their generating assets or market value them by the end of the AB 1890 transition period, and the only remaining utility retained generator (URG) that would not be subject to competitive market mechanisms would be QFs and other long-term power purchase contracts. Because utilities would be at risk in the market for recovery of their generation costs, it was important that they have assurance of recovery of these identified costs through an ongoing CTC charge.

After the extreme escalation in wholesale prices beginning in Summer 2000, however, it became apparent that California's transition to electricity deregulation was not working. The Legislature enacted emergency measures early in 2001 to deal with the energy crisis. Among these measures was AB No. 6 from the First Extraordinary Legislative Session (AB 6X) which altered the landscape regarding recovery of ongoing transition costs, prohibiting divestiture of any "facility for the generation of electricity owned by a public utility" prior to January 1, 2006. Under AB 6X, the URG portfolios are once again subject to cost-of-service ratemaking and include much more than the utilities' contractual obligations. AB 6X also amended existing statues to delete any reference to the market valuation of the utilities' generation assets, which had been an essential step in the calculation of the utilities' uneconomic costs. (Pub. Util. Code, § 367, subd. (b).)

As we concluded in D. 02-11-022, nothing in AB 6X rescinds the intent of the Commission that all customers, including DL served by Customer Generation, should pay their fair share of the above-market costs of QF and other utility purchased power contracts. The costs still must be recovered even if the underlying semantics have changed. The Settlement is consistent with this result.

The Commission is giving further consideration to issues surrounding the end of the rate freeze, along with the extent and disposition of transition costs left unrecovered. (D.02-01-011, p. 25 (slip op.).)⁵¹ Moreover, the Commission is also giving further consideration to what rate levels are necessary to assure utilities are reasonably creditworthy and financially healthy, in order for utilities to fulfill their responsibility to procure and deliver reliable, safe and adequate electricity. The result may or may not require a continuation of rates at frozen rate levels.

The timing of the end of the rate freeze, the corresponding impact on transition cost recovery, and the definition of what were formerly considered stranded costs are issues that are being considered in A.00-11-038 et al., in the rehearing of D.01-03-082, as ordered by D.02-01-001. We are also considering in that proceeding the impact of AB 6X and AB 1X on the various provisions of AB 1890. Here, we find that ongoing CTC should be included in the CRS applied to Customer Generation as set forth in the Settlement. This determination may be subject to subsequent adjustment, depending on our further consideration and determination in A.00-11-038 et al., and other related pending proceedings. We do not prejudge or intend to prejudge the outcome of these pending matters in today's decision. Accordingly, we reserve the option of revisiting the treatment of tail CTC as adopted in this order if necessary to conform to any subsequent Commission disposition of the tail CTC issue.

Eastside Power Authority requests that the Settlement Agreement be modified to provide for "the continuation of the CTC exemption for entities provided in Direct Access legislation AB 1890."⁵² To the extent certain parties may have statutory exemptions from CTCs, the Settlement Agreement does not change those statutory exemptions, as explained in Section 8.1 of the Settlement. Therefore additional language proposed by Eastside is unnecessary.

D. SCE'S Historical Procurement Charge

1. Parties' Positions - Pre-Settlement

In its opening testimony in this phase of the proceeding, SCE proposed to apply the HPC to DL customers on the same basis as was adopted for DA customers in D.02-07-032. The HPC, as adopted in D.02-07-032, provided recovery of SCE's past procurement cost undercollections as measured by the starting balance in SCE's "Procurement Related Obligation Account" (PROACT). Because DL customers affected by SCE's HPC proposal did not receive adequate notice, SCE agreed to withdraw its testimony in the A.98-07-003 proceeding proposing application of the HPC to DL customers. The HPC adopted in D.02-07-032 thus only applied to DA customers.

SCE argues that because the scope of this proceeding has been expanded to include recovery of costs from DL customers, it should be allowed to renew its proposal for application of the HPC to DL customers.

Real Energy and the Joint Parties argue affected DL parties still have had no opportunity to comment or to provide input regarding SCE's HPC because DL issues were specifically excluded from the A.98-07-003 proceeding where the HPC was litigated and adopted. These parties thus opposed SCE's proposal to apply an HPC to DL that was developed in a proceeding where DL was specifically excluded from consideration. These parties contend that SCE has offered no evidence as to what, if any, undercollection costs may have been incurred by DL customers. If the Commission chooses to impose an SCE HPC on DL customers, however, the parties argue that such charge should only be considered for DL customers that leave the utility system after a final decision is issued in this proceeding. Moreover, the parties argue that no HPC should be imposed against such DL customers absent a showing that some portion of the PROACT balance is attributable to them.

CLECA acknowledges that "departing load customers should pay for their share of past undercollections by both their serving utility and the DWR" and therefore agrees that "the HPC may be appropriate."⁵³ CPA argues, however, that new qualifying Customer Generation falling within the annual MW caps should also possibly be exempt from SCE and PG&E's historic charges, citing the "state's expressed need to increase energy supply resources in California and the Commission's recognition of "distributed generation as a desired new resource.⁵⁴" Similarly, Capstone argues that small clean distributed generation should be exempted from utility historical costs based on the "offsetting benefits" of such generation.⁵⁵

2. Discussion

Various parties categorically oppose any surcharge on DL, including the HPC, based on public policy considerations as outlined previously. No party, however, offered any specific criticisms in comments on the Settlement regarding the HPC recovery treatment proposed in the Settlement. We conclude that Section 7.1 represents a reasonable compromise of the positions taken regarding recovery of SCE's HPC, and is consistent with the record and the law. Accordingly, we approve of the Settlement's treatment of SCE's recovery of its HPC from DL served by Customer Generation.