SDG&E's Analyses and Proposals

On January 1, 2003, SDG&E resumed procurement of its residual net short position and assumed operational control of various DWR long-term contracts, which SDG&E dispatches along with its own supply resources as a single, integrated portfolio. The 2005 resource supply forecasts contained in SDG&E's application were developed using the production cost model, ProSym, from Henwood Energy Services, Inc. SDG&E and DWR resources were modeled in ProSym, which dispatched them to serve SDG&E bundled load, based on a forecast of 2005 natural gas and electric prices. The 2005 forecast of SDG&E bundled load used in this proceeding is the same load forecast used in SDG&E's long-term resource filing in Rulemaking 04-04-003. The price forecast was based on an assessment of market prices on September 1, 2004. The forecast of the 2005 supply resources is shown in Attachment B to Exhibit 1.

The primary change in the SDG&E electric resource portfolio from 2004 to 2005 is the addition of a gas-fired combustion turbine, Miramar CT1 (nominal load 46 Megawatts). This new resource is being added as the result of a recent competitive procurement process for grid reliability resources and is expected to be operational by June 2005. Other elements of the resource mix include a 20% interest in the San Onofre Nuclear Generating Station (SONGS), a long-term power purchase agreement with Portland General Electric (PGE) for 15% of the output of the Boardman coal-fired plant, qualifying facility (QF) contracts, renewable energy contracts, market purchases and sales of surplus energy. There are no resource changes in 2005 to the DWR contracts allocated to SDG&E and no assumptions are made about the outcome of SDG&E's current renewable resource procurement cycle. Any new renewable contracts awarded in the current renewable resource procurement cycle that results in delivery of energy to SDG&E in 2005 will displace either DWR contract energy or SDG&E market purchases.

For the purposes of this proceeding, we find SDG&E's resource supply forecast for 2005 to be reasonable.

The costs of some SDG&E power purchase contracts, which were in effect at the start of the Independent System Operator (ISO)/Power Exchange markets, qualify as Competitive Transition Charges (CTC). Expenses from CTC contracts are split between ERRA and the Transition Cost Balancing Account (TCBA). The costs from CTC contracts up to a market proxy price are booked to the ERRA, and any remaining contract costs above the market proxy price are booked to the TCBA, as directed by D.02-12-074.

SDG&E's current market proxy price is $43 per Megawatt-hours (MWh), as set by the Commission in D.02-11-022. SDG&E proposes to update this price to reflect the same projected market conditions that were used in its production cost model to forecast 2005 ERRA expenses in this application. SDG&E used its forecast of 2005 monthly on-peak and off-peak electric market prices, developed from a consultant's market assessment, to update the market proxy price. Attachment E to Exhibit 1 shows the market price forecast used in the production cost model run and the derivation of SDG&E's updated market proxy price of $53/MWh. We find this updated price reasonable for use in this proceeding.4

The majority of the costs that SDG&E incurs from its power purchase contracts, generation resources and market purchases used to serve bundled load are recorded to the ERRA. In addition, ISO charges, SDG&E's share of surplus energy sale revenues and any brokerage fees associated with market purchases are booked to the ERRA. In Exhibit 1, SDG&E describes and quantifies the costs included in its ERRA expense forecast for 2005.

For SONGS, only nuclear fuel expenses and associated fuel carrying charges are booked to the ERRA. All other costs are booked to the Non-fuel Generation Balancing Account (NGBA).

The costs incurred under the PGE Boardman long-term purchased power contract include energy, capacity, transmission to the ISO grid and SDG&E's share of any capital additions to the unit. Since this contract is a CTC contract, the expense recorded to the ERRA is determined by multiplying the forecast energy forecast production by the proposed market proxy price of $53/MWh.

Except for Kelco, all QF contracts are CTC contracts. The ERRA expenses for the CTC contracts are therefore based on delivered energy multiplied by the proposed market proxy price of $53/KWh. The total contract costs for Kelco are recorded as an ERRA expense.

All costs associated with renewable energy contracts are booked to the ERRA. Attachment D to Exhibit 1 details the projects by fuel type, their costs and forecast energy deliveries.

Once operational, SDG&E will assume ownership of the Miramar CT1. The capital costs and operating costs associated with this resource will be recovered through the NGBA, but fuel costs will become an ERRA expense.5 This resource, which has an Reliability Must-Run (RMR) condition 1 contract with the ISO, has the potential to be dispatched by SDG&E under least cost dispatch to serve bundled load or be dispatched by the ISO for local reliability.

SDG&E indicates that it has sufficient capacity to meet expected load, absent forced outages, without having to make market purchases, and only makes market purchases when it is economic to do so (i.e., when least cost dispatch criteria demonstrate that it is economic to make a purchase from the market rather than to use an available DWR dispatchable resource). The ERRA includes all costs associated with market purchases.

When SDG&E makes forward sales of surplus energy, the revenues from the sale of surplus energy is shared with DWR on a pro-rata basis in accordance with the operating agreement with DWR. SDG&E's share of the revenues is included in the ERRA.

ISO related costs include ISO-purchased ancillary services, transmission losses on certain URG resources, other ISO costs (such as neutrality, intrazonal congestion, must offer minimum load charges and unaccounted for energy), and ISO grid management charges. Also, SDG&E has purchased firm transmission rights (FTR) in 2003 and 2004 as a hedge against congestion costs, and expects to purchase similar rights in 2005. The costs paid to the ISO for FTRs are booked to the ERRA along with the congestion revenue payments from the ISO that accrue to FTR holders.

Based on SDG&E's forecast of supply resources and its explanation of the various related ERRA expenses, as summarized above, we find its ERRA expense forecast for 2005, as detailed in Attachment A to Exhibit 1 and totaling $296,981,000, to be reasonable.

As discussed above, we have found SDG&E's forecasts of supply resources and the related ERRA expenses to be reasonable. We also note that the associated ERRA revenue requirement forecast for 2005 will be trued up to reflect recorded costs through the balancing account procedures and will be subject to reasonableness review in a future Commission proceeding. For these reasons, we also find SDG&E's 2005 ERRA revenue requirement forecast of $301,106,000 to be reasonable.6

The implementation of rates associated with the 2005 revenue requirement forecast would result in a rate increase of 0.110 cents/KWh (0.80%, on a total system basis). However, SDG&E is not requesting any rate change for 2005 in this proceeding,7 and ERRA rates will not be adjusted at this time. The need for the minor rate increase is offset to an extent by the fact that SDG&E's ERRA is currently overcollected. Also, if the ERRA, at some point, becomes significantly undercollected, SDG&E must file an application to adjust rates through the trigger mechanism, as discussed below.

SDG&E's ERRA is subject to a trigger mechanism that requires the filing of a rate change application at any time that SDG&E's monthly forecasts indicate that the ERRA will face an undercollection or overcollection in excess of 5%. The mechanism considers the relationship between the monthly balance (overcollected or undercollected) in the ERRA and the prior year's recorded electric commodity revenues, excluding revenues collected for the DWR. D.02-10-062 requires that in any month when the balance in the ERRA reaches 4% of the prior year's recorded electric revenues excluding DWR revenue, SDG&E will file an expedited application that will ensure timely recovery of the projected ERRA balance. The application must include a projected balance in 60 days or more from the date of the filing depending on when the balance in the ERRA will reach the 5% threshold. SDG&E indicates that its prior year's (2003) revenue, excluding DWR revenues, was $600,261,657. Consequently, for 2004, SDG&E's 5% threshold is $30,013,000 and the 4% threshold is $24,010,000.

In its filing, SDG&E presented information on its ERRA balance from October 2003 through August 2004. The balance as of August 31, 2004 was an overcollection of $19.5 million. Based on the 5% threshold for 2004 there is no need, at this time, for any rate changes associated with the ERRA trigger mechanism.8

For 2005, revised 5% and 4% thresholds, based on 2004 revenues, must be developed. SDG&E should make the appropriate calculations and reflect the revised thresholds in its ERRA tariff as soon as the relevant 2004 revenue information is available.

4 Updating of the market proxy price is consistent with D.03-07-030 where we stated, "Since it was the intent in D.02-11-022 to adopt the 4.3¢ per kilowatt-hour (kWh) as an initial benchmark for use in determining above-market resource costs, parties should apply this value for computing CTC for the years 2001 through 2003. For the year 2004 and subsequent years, the 4.3¢ benchmark will be subject to revision to reflect more updated data." (D.03-07-030, pages 13-14.) 5 This ratemaking treatment was proposed by SDG&E in Advice Letter 1621-E and adopted by the Commission in Resolution E-3896 on January 27, 2005. 6 The revenue requirement is developed in Exhibit 2, Table 1. 7 In its filing SDG&E states that the Commission had not yet approved other significant pieces of SDG&E's total electric commodity rate, including the permanent allocation of the DWR revenue requirement and the SONGS non-fuel costs. For that reason, SDG&E indicated that, at an appropriate time in the future, it would make the appropriate filing to incorporate all the various revenue requirement components. Since the filing of the ERRA application, SDG&E's SONGS non-fuel costs were authorized by D.04-12-015. Also, in D.04-12-014, the Commission adopted a permanent methodology for allocating the DWR annual revenue requirement between PG&E, Southern California Edison Company and SDG&E. However, SDG&E was granted a limited rehearing of the DWR decision by D.05-01-036, and a consolidated rate change with the ERRA is a possibility. 8 By letter of October 13, 2004 to the Commission's Executive Director, SDG&E requested an extension of time to comply with the ERRA trigger mechanism, indicating that overcollections in its ERRA were expected to exceed the 4% trigger by September 30, 2004 but that pending Commission decisions would reduce the overcollection. SDG&E expected to drop below the 4% trigger in the normal course of business over the next several months and indicated a trigger would not be an efficient use of Commission personnel and time. By letter of November 8, 2004, the Executive Director granted the requested extension on the condition that the ERRA balance remains under the 5% cap. SDG&E was told that if the ERRA reaches the 5% cap, it must file an expedited application and provide customer notice as soon as possible.

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