XV. Proposals for DA CRS Covering Costs Other than DWR Procurement

A. Introduction

We now consider the issue of how the DA CRS component for non-DWR utility-related costs should be determined. 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,⁷⁹ the determination of ongoing CTC applicable to DA customers remains to be addressed in this proceeding.

SDG&E is the only utility that currently has an ongoing CTC charge in its tariffs. But this charge was established prior to the termination of the PX short-run markets, and was based on the PX price at the time. When the energy crisis occurred, theoretically that charge should have become negative owing to the very high PX prices. But ORA and SDG&E recommended freezing the existing CTC charge and to use the revenues it generated to pay down the undercollections created by SDG&E's rate freeze instituted through AB 265 and AB 43.

We now consider the parties' proposals concerning calculation of this element.

B. Parties' Positions

1. PG&E Proposal

In this proceeding, PG&E proposes to establish DA CRS to recover ongoing CTC relating to employee transition costs and above-market costs of qualifying facilities (QFs) and other purchased power agreements (PPAs) in place as of December 20, 1995.

PG&E proposes that QF capacity payments and the WAPA revenues be used to establish the above-market component of the Ongoing CTC. Thus, the cost of QF energy payments, the costs associated with PG&E's pre-December 20, 1995, non-WAPA PPAs, and the costs of PG&E's bilateral contracts would be treated as economic and excluded from Ongoing CTC. PG&E believes QF energy payments serve as a reasonable proxy for the market component in measuring CTC.

PG&E is opposed in principle with attempts to derive an explicit market benchmark proxy for purposes of measuring the above-market CTC component. PG&E argues that there is simply no reliable market benchmark at this point, given the current uncertainties regarding the market. PG&E's approach does not require determination of a separate benchmark proxy, but simply entails separating QF capacity payments and WAPA costs as the above-market components subject to CTC, and excluding all other URG components.

QF cost components typically consist of energy and capacity payments. The energy component is generally tied to either the "short-run avoided cost" (SRAC) methodology or to fixed energy prices, both of which have been approved by the Commission. PG&E's formula escalates a historical base SRAC energy price in connection with the change in current gas border price indices in relation to a base gas price.

Last year, the Commission established a pricing benchmark known as the Consumer Transition Price for QF prices consistent with the average price of the California DWR contract portfolio, which was characterized as "represent[ing] a current survey of the market for long-term supply comparable to that which is offered by QFs."⁸⁰ The 5.37 cents per/kWh five-year fixed energy price option allowed under D.01-06-015 was developed to be consistent with the requirements of D.01-03-067.

In the aggregate, the average price of PG&E's non-WAPA, pre-December 20, 1995, PPAs is well below the QF energy price just described. As such, PG&E excludes them from Ongoing CTC, as well. Because the bilaterals were not in existence on December 20, 1995, they are not a part of the Ongoing CTC.

PG&E forecasts the QF and other PPA component of its Ongoing CTC to be $404,054,000 for 2003. As shown in the Table below, PG&E proposes that its Ongoing CTC costs for 2003 be set at $405,014,000, equivalent to an average CTC rate of $0.519 cents/kWh.⁸¹

PACIFIC GAS AND ELECTRIC COMPANY
ONGOING CTC

2. SCE Proposal

SCE proposes that the above-market costs of its Utility Retained Generation (URG) portfolio and employee-related transition costs be allocated to all customers, consistent with the Commission's direction in D.00-06-034. SCE proposes that a DA cost responsibility component be established based on the costs associated with its URG portfolio as well as any other costs identified in Public Utilities Code Section 367 which are not related to that portfolio.

SCE defines its URG portfolio to consist of nuclear, hydro, and coal generation assets as well as long-term QF and inter-utility contracts. SCE argues that both current bundled service customers, as well as those who elected DA, should equally bear cost responsibility for this portfolio.⁸³ SCE proposes a charge applicable to all DA customers, regardless of the date they entered into DA contracts, to recover their share of the difference between the cost of the portfolio and its value under market conditions in any given year.

SCE proposes to calculate the charge associated with its above-market costs as the difference between the cost of the URG portfolio and its estimated value in the market. The charge would thus apply the same "stranded cost" approach the Commission previously adopted for the calculation of the CTC. Thus, DA customers will be responsible for the same proportional share of "stranded costs" as bundled service customers will bear. Depending on the market conditions, the market value of this portfolio in some years could exceed its costs. Under such circumstances, DA customers would receive their share of this benefit provided that, when combined with all other charges and credits to DA customers, this benefit does not result in a credit to those customers that exceeds the generation rate of their Otherwise Applicable Tariff (OAT).

In D.02-04-016, the Commission authorized 2002 revenue requirements associated with SCE's Native Load, Purchased Power and ISO Charges for SCE of $3.772 billion.⁸⁴ This revenue requirement is comprised of: (a) the operating expenses and capital-related costs for SCE's nuclear, fossil, and

hydro generating stations;⁸⁵ (b) the costs of its energy and capacity purchases through QF, bilateral contracts and inter-utility contracts, including contract buyouts and scheduling and dispatching costs; and (c) associated IISO charges.⁸⁶ SCE proposes that this revenue requirement be compared to the estimated market value of the output of SCE's URG portfolio to calculate the initial DA CRS to be assessed to the DA customers.

SCE proposes a methodology for determining URG market value using a benchmark price that incorporates many of the same sources as SDG&E for published market prices, applies a more detailed regression analysis. SCE also ignores some of the information available in its sources regarding off peak prices, but instead calculates an off peak price using historical data. SDG&E argues that using the available off-peak price data contained in its proposed sources would be a much simpler and more valid alternative to calculating off peak prices based on their historic relationship to on-peak prices. SCE also proposes to develop a simulated portfolio of spot market contracts that approximates its CTC generation supply profile as a means to develop market prices.

After the Commission issues a decision in SCE's 2003 General Rate Case (GRC), some of SCE's URG costs, such as the O&M costs, will likely be set on a forecast basis without a requirement for future true-ups, while other costs such as fuel-related costs continue to be subject to the balancing account treatment. In D.02-04-016, the Commission ordered SCE to record its actual costs to a balancing account and to true up the URG revenue requirement based on those recorded URG costs in the following year. Therefore, SCE proposes to use the above revenue requirement and compare it with the estimated market value of the output of its URG portfolio to calculate the initial DA CRS to be assessed to the DA customers. This charge would be subject to true up as the URG revenue requirement is trued up to the actual recorded URG costs. Based on SCE's proposed 3.62 cents/kWh market benchmark, as described previously, the resulting URG market value amounts to $2.205 billion, leaving a net amount of above-market costs of $1.490 billion, to be allocated among all customers, including DA customers.

Assuming that some of its URG costs will be set on a forecast basis without future true ups, while other costs will continue to be subject to balancing account requirements, SCE proposes to continue to calculate an annual URG revenue requirement for determination of DA CRS. This charge would then be trued up in the following year only for those costs that are subject to balancing account treatment.

3. SDG&E Proposal

SDG&E proposes that the Commission: (a) maintain SDG&E's current CTC charges for 2003, and continue applying these charges to both bundled and DA customers, as authorized under AB 1890; (b) revise the current SDG&E accounting process to ensure that DA customers pay their approximate share of the eligible above-market URG costs through the CTC, as mandated by AB 1890; and (c) use market indices, as proposed by SDG&E Witness Nelson to determine the above-market costs of SDG&E's URG eligible for CTC recovery.

SDG&E proposes to maintain its current combined CTC and URG rate structures for AB 265 customers until such time that the AB 265 undercollection is completely recovered. Once the AB 265 undercollection is fully recovered, SDG&E will revise its URG revenue requirement to exclude the above-market portion of URG costs that will continue to flow to the Transition Cost Balancing Account (TCBA) and be recovered through ongoing CTC charges. SDG&E believes that both bundled and DA customers remain responsible for ongoing CTC charges to recover above-market URG costs.

Although witness Nelson provided a revised CTC revenue requirement, representing estimated 2003 above-market URG costs for eligible assets, SDG&E proposes to keep the current CTC charges in place for 2003, in the interest of stability in what customers pay. SDG&E states that whereas PG&E and SCE are still subject to their AB 1890-mandate rate freezes and still have bundled rates in which their CTC charges are a residual component, since July 1999, SDG&E's CTC charges have been unbundled from its other charges.

Under SDG&E's proposal, the CTC revenue requirement will continue to be allocated to AB 265 customers and AB 43 customers in the current 60/40 ratio. Beginning in 2004, until such time the AB 265 undercollection is eliminated, the AB 265 portion of the CTC revenue requirement shall be the greater of the current authorized revenue requirement allocated to AB 265 customers (approximately $70 million) or 60% of the total revenue requirement. The difference between the total above-market URG estimate and the portion allocated to AB 265 customers will be the AB 43 portion of the CTC revenue requirement.

SDG&E's forecast of above-market URG costs for qualifying generation requires projections of delivered energy and actual generation cost, and a forecast of the SP15 market indices described below. SDG&E's latest projections of its URG energy and generation cost are contained in its Procurement OIR filings (R.01-10-024) for daily bilateral purchases.⁸⁷ Only the qualifying URG from that filing is used in SDG&E's forecast of CTC revenue requirements. SDG&E proposes an averaging two published market indices⁸⁸ for standard on-peak and off-peak contract prices, with an SP 15 delivery point, traded in the daily bilateral market. SDG&E claims its proposal offers the best replacement for the California PX price, which was previously used to determine the CTC generation market value. SDG&E claims that the market benchmark proposals of other parties fail to account for key aspects that influence the determination of CTC generation market value.

SONGS costs for 2003 will be determined by SONGS ICIP. Costs for SDG&E QF generation will be based on the individual QF contract costs for energy and capacity. This includes those QF contracts⁸⁹ that now have a five-year fixed energy price, pursuant to D.01-06-015 and D.01-09-021. For those QF contracts with energy payments based on short-run avoided costs (SRAC), SDG&E's BCAP gas price forecast was used. Costs for the PGE purchased power will include contract costs for energy, capacity and any contractual capital cost obligations. Transmission costs for delivery of the PGE energy to the ISO-controlled grid will also be included as a CTC cost.

SDG&E's forecast of its 2003 revenue requirement of $132.9 million⁹⁰ for generation that it proposes as qualifying for CTC recovery is set forth below:

CTC Generation (in GWh) 5,898.4

Generation Cost in K$ $ 331,902

Less: Generation Market Value in K$ ($198,984)

CTC Costs in K$ $132,918

Given the fact that the $132.9 million is a forecast is fairly close to SDG&E's currently adopted CTC revenue requirement of $115 million and in the interest of stabilizing what customers pay, SDG&E's recommendation is that current CTC rate levels be continued in 2003.⁹¹ This position is consistent with the position of ORA that SDG&E CTC charges remain at current levels.⁹²

SDG&E proposes the following prospective treatment of CTC. On a monthly basis beginning January 2003, the recorded above-market URG costs for eligible assets will flow to the TCBA and be split appropriately (60%/40%) between the AB 265 and ABX1 43 subaccounts, respectively. The revenue generated from the CTC charge each month will also flow to the respective subaccounts in the same proportion as the derivation of the CTC revenue requirement described above. After 2003, SDG&E will revise its CTC revenue requirement each year in an appropriate Commission proceeding (such as the Annual Transition Cost Proceeding) to reflect the upcoming year's forecast of eligible above-market URG costs plus the 12-month amortization of the prior year's balance in the TCBA. For the TCBA balance allocated to AB 265 customers, the 12-month amortization of the TCBA will not occur for a prior year overcollected balance until the AB 265 undercollection is fully recovered.

In order to continue the recovery of the AB 265 undercollection as provided by the existing CTC revenue requirement, SDG&E proposes to continue billing its electric commodity rates at their current levels. In conjunction with A.02-01-015, the total revenues generated by the URG component of electric commodity rates will be recorded to the PECA, or its successor, beginning in January 1, 2003. Pursuant to SDG&E's adopted tariffs, any overcollection in the PECA is to be transferred to the TCBA annually. Seventy percent (70%) of the PECA is allocated to the AB 265 undercollection as that percentage reflects the approximate share of SDG&E's total bundled service customer usage (excluding direct access) subject to AB 265. As previously described, once the AB 265 undercollection is fully recovered, SDG&E will revise its URG revenue requirement to exclude the above-market portion of eligible URG assets, which is being recovered as part of the CTC revenue requirement.

4. ORA

ORA's proposed ongoing CTC for PG&E is $9.61/MWh and for SCE is $14.79/MWh. SCE's proposed HPC for 2003-2004 is $25/MWh, and a similar undercollection fee could be imposed on PG&E. Thus, the ORA's combined charges for PG&E DA customers would be $62-87/MWh and for SCE DA customers would be $69-$94/MWh.

ORA presented an illustrative calculation of an ongoing CTC for DA customers using July 2001 - June 2002 costs adopted in D.02-04-016, and the 2001 - 2002 spot price used in DWR Scenario 8 surcharge calculation. TURN supports ORA's market proxy approach, using spot market purchases by DWR or the utility as the measure of market prices. In ORA's illustration, the 2001 - 2002 system average CTC rate for PG&E is $9.61/mWh (Table 5-1), and SCE is $14.79/mWh⁹³ (Table 5-2). The CTC charge varies by class in the illustration since transition costs have been allocated to class and rate schedule using the top 100 hours method adopted in D.00-06-034.

5. CMTA

CMTA takes issue with PG&E's quantification of ongoing CTC in that it only focuses on specific URG resources that are above market, such as QF contracts, but does not reduce ongoing CTC to reflect below-market resources, such as hydro. CMTA also disagrees with the market benchmarks used by other parties.

CMTA proposes using a benchmark based on the all-in costs of a new gas-fired combined-cycle power plant, which includes both variable operating and fixed capital costs. CMTA claims this is the same benchmark that the Commission endorsed in its complaint before FERC in which it seeks to modify the DWR contracts.⁹⁴ CMTA argues that such a benchmark is conservative to the extent that (1) combined-cycle plants tend to be less expensive base load resources and (2) DWR long-term contracts include a substantial amount of more expensive peaking capacity. CMTA proposes that the different natural gas prices between northern and southern California be weighted using the allocation of net short requirements met by DWR contracts. On this basis, approximately 40% of the benchmark would be weighted with northern and 60% weighted with southern California prices. CMTA argues that using a spot price benchmark would be an "apples to oranges" comparison since DWR's contracts are long-term in nature. It alleges that spot market prices are largely irrelevant to assessing the economic viability of these long term-contracts. CMTA argues that its long-term benchmark is easy to calculate and is logical because many of the DWR contracts at issue in this proceeding purchase power from new combined-cycle plants in California.

CMTA's benchmark incorporates a weighted average natural gas price (40% for northern; 60% for southern California) consistent with how the DWR long-term contracts are allocated geographically. The above-market DWR costs as determined by the use of the benchmark are then allocated across all bundled and incremental direct access loads based on each rate group's share of the highest 100 hours of system loads.

CMTA's proposes that its long-term benchmark be used to measure above-market URG costs. Like the DWR contracts, the URG portfolio consists of long-term resources owned by the IOUs or under long-term contract to serve the IOUs. Thus, in order to conduct an "apples to apples" assessment, a long-term benchmark is appropriate. However, because each IOU's URG portfolio is different, CMTA proposes that the URG cost components should be individually calculated and allocated for each IOU.

6. CLECA

CLECA argues that combining charges developed using the DWR method with a separate CTC charge will require DA customers to significantly subsidize bundled customers. CLECA argues that it is more appropriate to look at the entire bundled portfolio to determine whether the departure of DA load has increased the costs for remaining bundled service customers. The bundled portfolio will contain some above-market power (e.g., QF contracts, DWR power) and some below-market power (e.g., utility hydro, nuclear, and coal generation). CLECA also argues that applying a CTC charge only to the above-market URG, e.g., QF contracts, again reduces the average cost of electricity for bundled customers even further because their share of the below-market URG increases at the 13.6% DA level relative to the 2% DA level. In order to avoid any subsidization, CLECA believes that the entire utility portfolio must be considered, i.e., for each utility, all URG and its pro rata share of DWR power should be combined together in determining how much DA customers must contribute to keep bundled customers indifferent.

C. Discussion

We shall implement the DA CRS relating to the above-market portion of utility-related costs in the following manner. We shall direct that an updated calculation of above-market utility-related costs be performed utilizing the updated URG and PPA/QF costs that are adopted pursuant to the Procurement OIR (R.01-10-024). Calculating ongoing CTC requires a market price. CTC was defined in D.97-06-060 and D.97-11-074 as being the difference between the utilities actual cost of a particular asset or contract and the short-term Power Exchange (PX) price. When D.00-06-034 was issued, the PX was still operating its short-term markets. In the absence of a PX price, a new market price benchmark must be established for use in calculating CTC.

The above-market portion of these costs shall be determined by comparing the market value of utility-related resources using a designated market proxy, as we explain below.

We appreciate the difficulties in identifying a realistic measure of a market proxy given the current unsettled state of power markets. Nonetheless, we must develop a measure in order to calculate a separate CTC charge for DA customers. Although there are advantages and disadvantages to each of the proposed approaches, on balance, we find that the use of a gas-fired combined cycle unit offers the most appropriate proxy measure. We conclude that spot price proxies are too unstable and unreliable to form the basis for a market proxy.

The demise of the California PX has reduced the size and transparency of the spot market. Even though the California ISO continues to run a real-time market for balancing energy, and bilateral market prices continue to be reported, the data is very limited.⁹⁵ Spot electric prices may become even more volatile and unpredictable because of the ISO market redesign efforts and FERC oversight.⁹⁶ FERC's existing spot market cap of $91/MWh will expire as of September 30 and will be replaced by a $250/MWh price cap.⁹⁷ Thus, in the interest of providing more stability and a cost-based approach, we conclude that a benchmark based on the long-term cost of operating a combined-cycle unit offers the best result.

We are concerned, however, that the reported values for a combined cycle proxy offered by CMTA seem rather high when compared with other parties' proposed measures. CMTA's benchmark price ranges from $43.86 to $53.75/mWh over a 10-year period. By contrast, the current market prices for ten-year supply contracts based on actual market prices range from $40.52 to $43.53, as reported by Strategic Energy Witness Lacy.⁹⁸

CMTA's explanation that values will vary over time does not fully satisfy our concerns as to its measures of the magnitude of the proxy. If in fact, such values vary over time, we find the alternative value for a combined cycle unit offered by ORA to be preferable since it is based on a 15-year levelized cost calculation. We shall thus adopt the combined cycle proxy value of 4.3 cents/kWh cited in ORA's testimony as the benchmark for purposes of calculating indifference costs under this order.

We adopt the 4.3 cents/kWh specifically for the 2003 DA CRS calculations. We emphasize that the market proxy value should be regularly updated with each annual updating of the DA CRS component for URG to reflect the most current and reliable data.