VI. Short-Term Plans

A. Overview

The objectives of each utility's procurement process should be (1) to ensure sufficient and reliable energy supply at low and stable rates and (2) to optimize the value of its overall supply portfolio for the benefit of its customers. We recognize that an incentive mechanism is needed to fully align the interests of the utilities and ratepayers and, as discussed in Section V.C.2, the development of such a mechanism within early 2004 is a high priority of the Commission.

Our review of each utility's short-term plan raises concerns in four areas, and we make modifications to ensure that:

_ effective mechanisms for measuring and managing portfolio price risk are in place;

_ each utility is given flexibility to sign multi-year contracts, but with certain limitations placed on this authority to preclude a utility from locking up all needs for the next five years while the Commission works to implement programs in renewables, energy efficiency, and demand reduction;

_ upfront standards are proposed that mitigate the possibility of customers significantly overpaying for procurement products; and

_ transparent markets and competitive procurement processes are used unless a strong showing is made that ratepayers benefit from bilaterally negotiated transactions.

In preparing their 2004 plans, the utilities focus on the planning and procurement process that takes place as they move from a twelve month or less position to the actual delivery of electricity to their customers. For this short-term look, the utility's focus is on measuring the price risk exposure of its open portfolio position and managing that position, within a specified consumer risk tolerance level, in a manner that ultimately leads to the procurement and dispatch of power in a least-cost manner. As PG&E's procurement guidelines state: transactions are based on defined customer needs; the utility should not arbitrage in energy markets.¹¹⁰

The planning and procurement process is conceptually identical in all timeframes; however, the input assumptions and the granularity of those assumptions become more focused and certain as the operating timeframe approaches real-time.

The table below seeks to illustrate the process that a utility employs to conducts procurement planning and transaction execution. This table was adapted from PG&E's 2004 ERRA testimony, pages 2-16 and 2-17.

Utility Resource Planning & Dispatch Process

Time Horizon	Input Assumptions	Output and Action
Annual (Conducted on a regular 12-month rolling basis)	Hydro, load, price scenarios (based on forward prices), resource availability.	Forecasted net open position estimate. Formulate strategies for managing open position (identify transaction types and amounts, price thresholds). Assess impact of open position on risk management policy. Make gas supply decisions and volume nominations. Implement procurement strategy and confer with PRG.
Quarterly/ Monthly/Intra-Month	Updates to load, price, and resource availability assumptions.	Forecasted net open position estimate. Formulate strategies for managing open position (identify transaction types and amounts, price thresholds). Schedule plant maintenance. Schedule DWR contracts. Make gas supply decisions and volume nominations. Implement procurement strategy and confer with PRG, if needed.
Weekly Planning	Updates to weekly hydro system operating plan, plant availability, and market prices.	Forecasted net open position estimate. Formulate strategies for managing net open position (identify transaction types and amounts, price thresholds). Schedule DWR contracts. Make gas supply decisions and volume nominations.
Daily Planning	Adjust load forecast, hydro conditions, plant availability, current market prices, transmission constraints, assess activities of ISO operations, pre-scheduling (hourly) of hydro.	Conduct least-cost analysis to determine unit dispatch and market transactions. Strategies for managing open position (identify transaction types and amounts, price thresholds) are conveyed to Day-Ahead traders and Real-Time operators. Re-schedule operations of retained hydro generation to reflect updated conditions. Schedule DWR contracts and other existing contracts. Counterparties are advised per contract terms. Day-Ahead transactions are executed. Market prices are monitored via brokers and electronic exchanges and procurement strategies are revised as needed.
Hour Ahead	Updates to load forecast, hydro conditions, plant availability, market prices. Actual loads are monitored. Retained generation is monitored. Assess activities of ISO operations.	Manage open positions with Hour-Ahead transactions. Monitor market prices. Re-schedule operations of retained hydro generation to reflect updated conditions. Re-schedule DWR contracts to reflect current conditions. Respond to ISO Reliability Must Run calls and further revise schedules of retained generation and DWR contracts as needed.

B. Review of Risk Management and Reporting Proposals

Our discussion here will focus on (1) refinements to risk management and reporting the Commission directed be given further review in D.02-10-062 and D.02-12-074; and (2) changes the utilities request in their 2004 short term plans that are substantially different from the existing authority they have under their 2003 plans.

1. Consistent Measurement of Degree of Portfolio Risk

In the 2003 short-term plans adopted last year, each utility proposed its own tools and framework to measure portfolio risk, we agreed with ORA's position that the utilities should move in the direction of analyzing portfolio risk based on a probability distribution of risk drivers, but we did not want to be prescriptive at that time in requiring the use of the Value at Risk (VaR) or Cash-Flow-at-Risk (CFAR) models. We approved, with modifications, the scenario approaches of PG&E and SCE and approved SDG&E's methodological approach without modification. Lastly, we directed Energy Division to schedule a workshop in early 2003 to assist us in gathering additional information on the subject of portfolio risk measurement. Energy Division held the workshop in April 2003 and filed a report on the use of probability distribution models with the Commission on June 6, 2003.

In their 2004 STPPs, both PG&E and SDG&E propose to use TeVaR (To Expiration Value at Risk), a type of VaR model, to measure and report risk and to trigger review of their hedging plans with the PRG.¹¹¹ SCE states it can report using a TeVaR model, but it is in the process of developing a proprietary, in-house model that uses "statistical distribution of portfolio costs....which will show the probability of each particular portfolio cost outcome." At the time of evidentiary hearing, SCE testified that this new model was in a conceptual stage of development. SCE asks that the Commission make a finding here to approve the concept and all development costs. SCE indicates that it will share the results of its in-house model with Commission staff and the PRG before using the model. On cross-examination, SCE's witness testified that the utility would be willing to have the model validated by an independent source.

ORA objects to SCE's request, testifying that if the model is still conceptual at this late stage, it is untimely for approval or consideration in this proceeding. ORA also states that ratepayers should not have to pay for development of this model.

TURN testifies in support of the VaR models and requests the utilities specifically focus on the concept of "Ratepayer Cost at Risk" in using the models.

Section 454.5 (b) (1) states that an electrical corporation's proposed procurement plan shall include "an assessment of the price risk associated with the electrical corporation's portfolio." The Commission has a fiduciary duty to ratepayers to ensure that this price assessment is conducted in a consistent manner, with standards of transparency inherent in today's commercially available risk management models. Based on the Energy Division's filed workshop report and based on the hearing record, the Commission has a better understanding of the nuances and complexities involved in measuring portfolio risk, as well as the features specific to each utility's energy portfolio.

We recommend that portfolio risk be reported using TeVaR. The VaR product is a staple of the financial industry. It was developed in the mid-1990's and is widely used by Wall Street as well as by non-financial blue-chip corporations. ORA testifies that all of the IOUs' holding companies indicate in their 2002 Annual Reports that they use a VaR model. The validity of VaR and other commercially available risk methodologies is that their commercial viability provides the Commission with a consistent and transparent benchmark through which IOU portfolio risk can be measured. As has been noted: "VaR has become a common language for communication about aggregate risk taking, both within an organization and outside (e.g., with analysts, regulators, rating agencies, and shareholders)."¹¹²

While we continue to believe that the Commission should not be overly proscriptive in directing utility risk management practices, we need to balance our preference for an "even-handed" treatment on procurement policy with an emphasis on transparency and consistency in risk management reporting. The Commission recognizes the importance of standardized risk reporting in order to measure ratepayer risk on an "apples-to-apples" basis and to ensure that utility procurement decisions will benefit all IOU ratepayers in an equitable and unbiased manner. By establishing a common benchmark, the Commission can assure itself that California's ratepayers, regardless of utility, are equally protected from adverse risk, and thereby can reap the benefits of reliable energy at low and stable rates.

While we adopt here the use of a consistent, transparent model for AB 57 compliance, SCE can continue to develop its own in-house model and bring it back for consideration here when it is fully developed and independently tested and verified. Cost recovery for this model would be sought through the General Rate Case (GRC) process, the same as all procurement administration expenses.

We now address the issue of the level of risk the utilities should report using TeVAR. The 95^th percentile, as indicated by SDG&E, accounts for all of the cost possibilities except for the last 5 percent of the high-end tail of the distribution of possibilities. Both SDG&E and ORA recommend this level as the standardized reporting measure. SCE states that it can report risk using its proprietary model at any confidence level, but does not advocate a specific level. PG&E recommends reporting at both the 95^th and the 99^th percentile, with use of the 99^th as the standard for managing its portfolio within the CRT.

We believe risk reporting should be a "roadmap," alerting the Commission of the relative risk in different time periods. At a 95^th percentile, we would not be aware of a 1 in 20 possibility. As discussed in relation to the interim CRT, we have found that the tolerance of California ratepayers for high price volatility is low, and the utilities should measure the probability of extreme price spikes all the probabilities, and then apply the one cent/kWh CRT. The current risk reporting is at 95^th percentile and under this standard, only twice has an IOU called a PRG meeting to discuss the situation (SDG&E on February 25, 2003 and PG&E on March 5, 2003). Based on this, we find a 99^th percentile reporting will provide additional price volatility protection and should not be burdensome to the IOUs. We are also guided by TURN's testimony that our risk management standards should be a protection against highly unlikely events. While we do not adopt PG&E's additional stress scenario proposal as a requirement, there may be instances, e.g., the gas price run-up earlier this year, where this analysis is prudent and we encourage the utilities to perform any additional scenario analysis they believe is warranted and to discuss this information with their PRG. With respect to portfolio risk notification, we adopt ORA's proposal that:

1. If between quarterly updates, a utility's estimated risk is over 125% of the CRT, the utility will promptly meet and confer with its PRG and discuss specific hedging strategies and plan modifications so that the value of the utility's open position will stay within the CRT.

2. Within 10 days of the PRG meeting, the utility will file plan modifications in the form of an expedited application.

3. Until the application is approved, the utility may purchase from spot markets, enter into bilateral trades, broker-assisted trades, or execute trades through an exchange.

Therefore, we adopt risk reporting using a by-product of VaR (TeVaR), measured on a 12-month rolling basis, at a 99% confidence level. Risk reporting should cover a longer period if the utility entered longer term transactions within the quarter.

C. Limits on Length and Volume of Contracts Authorized

Based on our review and parties comments, we find PG&E's and SDG&E's volumetric limits and length of contracts reasonable.

In D.02-12-074, the Commission agreed with concerns expressed by ORA and TURN regarding the prospect that SCE could over-procure energy and capacity. The proposals before us there and our findings are:

"Both ORA and TURN propose downward adjustments to Edison's position limits. ORA states that given the great degree of uncertainty regarding both the size of the 2003 RNS and the distribution of probable future electric market costs, and because customer risk aversion has not yet been measured, the Commission should be conservative and not authorize the utilities to sign excessive amounts of contracts for 2003. It also states that the Commission should keep in mind that, unlike during the energy crisis of 2000-2001, market prices only apply to about 5 to 10 percent of the market, not 100 percent. ORA recommends that the maximum RNS purchase limit be set to a specified percentage of the average hourly RNS for the reference or expected case. For Edison, ORA proposes a modified annual limit for capacity contracts, a modified monthly forward energy contract limit, as well as separate volume limits for gas contracts.

"TURN states it is concerned that Edison's plan appears completely focused on ensuring that Edison is not caught short in a period of price volatility while failing to contemplate the possibility of over-procurement and its adverse financial consequences for bundled ratepayers. TURN states that based on its review of the forecasts provided by Edison, the risks associated with potential high market prices (or total dysfunction) appear to be manageable even without locking in any major additional capacity commitments.

"As an additional measure to protect ratepayers, TURN proposes that Edison be authorized to procure only 50% of its proposed energy and capacity limits through transactions that do not require pre-approval by the Commission. To the extent that Edison believes that forward purchases of the remaining 50% will benefit ratepayers, it should be required to make a showing as part of a pre-approval process that does not presume reasonableness of the quantities or prices.

"We share the concerns of ORA and TURN regarding the prospect that Edison could over-procure energy and capacity. While recognizing that Edison proposes maximum limits that it may not in fact utilize, it is not prudent at this time to pre-approve these ceilings based on a worst-case RNS scenario. We are particularly concerned that Edison could over-hedge its position for a five-year term. This would effectively preclude the Commission's ability to consider renewable procurement under the Renewable Portfolio Standard (RPS), and additional energy efficiency and demand reduction programs for the 2004-2007 period in the long-term planning process. It would also preclude the Commission's ability to ensure that Edison responds in an economically efficient manner to possible reductions in its 2004-2007 RNS from community aggregation and other factors.

"Therefore, we adopt ORA's recommendation that Edison establish its monthly forward energy limit based on its Reference Case RNS-Reference Dispatch Scenario, with certain modifications that are specified in confidential Appendix B. We also adopt a modification of TURN's 50% recommendation to address five-year contract limits. We do not find sufficient justification in this record to adopt ORA's recommendations to further limit gas volumes."

In this proceeding, SCE again requests five year contracting authority, and, based on an escalating formula over 2004-8, it is for over 100% of its 2004 RNS needs. SCE proposes volume transaction limits based on its Reference Case scenario (rather than High Case scenario as it did last year), however, the 2004 Reference Case forecast for RNS filed here is 55% higher than the 2004 RNS High Case forecast included in SCE's 2003 plan. In addition:

_ SCE's 2004 average off-peak annual position limit for forward energy purchases is about 7 times the limit indicated in its 2003 plan (with the 2003 plan using a High Case scenario while the 2004 plan uses a Reference Case scenario);

_ SCE's 2004 average on-peak annual position limit for forward energy purchases is about 4 times the limit indicated in its 2003 plan, using the same scenarios described above.

_ SCE's 2004 plan's position limit for capacity contracts is over twice the MWs of its 2003 plan's position limit; and

_ SCE's 2004 plan's average monthly limit for natural gas hedging is about four times the average monthly limit in its 2003 plan. (Note: This monthly limit does not include QF gas hedging)

No party specifically testified on SCE's five-year request for authority. SCE's request is not in line with the authority requested by PG&E and SDG&E, and we are again concerned that granting this authority could effectively preclude our ability to consider renewable procurement under RPS, and additional energy efficiency and demand reduction programs for the 2005-2008 period in the long-term planning process, and that it could preclude SCE from effectively responding to the uncertainties it cites regarding its customer base. Therefore, we retain the existing modification of TURN's earlier 50% recommendation we adopted in D.02-12-074.

For the substantial changes in SCE's RNS forecast, we look to the testimony of Jan Reid of ORA. He states that RNS appears to be very difficult to model in the near term and that if pre-approval is given for a longer time and its essentially based on the RNS models, then you run the risk of significantly overpaying for what you thought were hedges at the time that you signed them.¹¹³

ORA does not specifically cite the RNS forecast variances we discuss here or the substantial changes in volume limits being requested. The only specific recommendation ORA provides, is to never allow a utility to hedge all its risk, and to limit all IOUs natural gas hedging for QF price risk to 73%.

We do not have a record here to find SCE's request for maximum volume limits based on its 2004 plan RNS and position limits for off-peak annual, on-peak annual, capacity contracts, forward energy sales, and average monthly limit for natural gas to be reasonable. We do find sufficient justification for SCE's proposals for gas storage capacity, to include associated injection and withdrawal rights, based on a certain term. We note that SCE's transmission and gas pipeline capacity requirements have yet to be determined, and direct that SCE make a filing when firm estimates become available.

We recognize that with pre-approved cost recovery and no incentive mechanism, there may be a perverse incentive for the utilities to pay too high a price to remove all risk. Therefore, we direct SCE use the 2004 RNS Reference Case forecast from its 2003 STPP and the transaction rates currently adopted.

We find ORA's proposal for a 73% limit on hedging for QF price risk to be reasonable and, therefore, adopt it.

D. Upfront Standards for Utility Procurement Products and Transactions ( was Consideration of 2004/5 Policies/Programs)

In D.02-10-062, Section VI, the Commission adopted a list of authorized products, specified authorized procurement transaction processes, and established upfront reasonableness guidelines for transactions. Parties propose various modifications in these areas.

1. Authorized Products

In D.02-12-062, we authorized the utilities to conduct procurement using a wide range of products and instructed the utilities to specify in their 2003 procurement plans the products they intend to use along with a definition of the product and the associated benefit/cost attributes. The specific procurement products that we authorized in D.02-12-062 are shown below. We continue to authorize the utilities to procure these products.

Table 1 Authorized Procurement Products
Transaction	Description	Benefit /Cost
Forward Spot (Day-Ahead & Hour-ahead (purchase, sale, or exchange)	Purchase pre-scheduled energy or load reductions at fixed price	Needed to balance short-term load/resource changes/ Vulnerable to price volatility
Real-time (purchase or sale)	Energy imbalance transactions or load reductions	Balances Short-term needs/ Vulnerable to price volatility
Forward Energy (purchase or sale)	Contracts entered into in advance of delivery time, includes block/forward products (e.g., fixed amounts of energy over a specified period of time (e.g., 7x24, 6x16, super-peak, and shaped products) Could be fixed price	Reduces price risk / Risk that prices will be below contracted rate
Forward Energy (demand side)	Baseload usage reduction through investments in permanent energy efficiency	Reduces price risk and cost overall
Capacity (purchase or sale)	Right to purchase energy in exchange for capacity payment. If exercised, buyer also pays incremental energy charge at specified rate	Reduces spot price risk / Reduced risk comes at cost of reservation and energy charges
Capacity (demand side)	Right to purchase load reductions for capacity payments	Provides dispatchable reliability
On-site energy or capacity	Energy or capacity products self-generated on the customer side of the meter	Provides locational reliability and lowers price risk through supply diversity
Tolling Agreement	Type of capacity product where buyer hedges fuel cost risk by providing the gas supply, transportation, and storage	Reduces peak price risk / Buyer pays reservation or capacity charges, and is open to gas price risk
Peak for off-peak exchange	Trades peak energy for off -peak energy (x peak MWh < y off-peak MWh)	Reduces peak price risks / Increases off-peak price risks
Seasonal exchange	Buyer receives peak energy in Summer and returns peak energy in Winter	Reduces summer price risk /Increases winter peak price risk
Physical call (or put) option	Deal to purchase energy in future at pre-set price (price may be pegged to an index). [Call is right to purchase, put is right to sell.]	Call reduces price risk, with option to not exercise right if prices lower. Put insulates from reduced value of excess energy / Fee associated with these rights
Financial call (or put) option	Caps energy price without losing the benefit of lower prices. Price of energy is capped at a fixed price; at times when an agreed upon index price falls below the fixed (strike) price, the buyer pays the lower index price	Reduces price risk / Reduced risk comes at price of option premium (fee)
Financial swap	Buyer gets or pays difference between floating price index and a fixed negotiated price	Locks in fixed price (reduces price risk) / Cost if negative difference between floating index and fixed price
Insurance (Counterparty credit insurance, cross commodity hedges)	Buyer can insure against various adverse events (such as extreme temperature, a generating unit failure, or counterparty default, among others), to reduce price risk	Insurance policies can reduce price risk, but increase energy costs by the amount of the insurance premium
Electricity Transmission Products	Arranged through CA ISO and with non-CAISO transmission owners. Also includes purchase of transmission rights or use of locational spreads.	Reduces price risk associated with varying transmission conditions.

Gas Transportation Transaction	Buyer contracts for transportation of gas to a determined delivery point, at a set price (could be fixed or variable) over a specified time-frame	Reduces price risk associated with gas transportation (and therefore, limits some electric generation price risk for gas-fired units)
Gas Storage	Buyer reserves gas storage capacity for a defined price	Hedges price risk associated with gas storage
Gas Purchases	Purchased on a monthly, multi-month, or annual block basis	Used to hedge fuel cost risk associated with capacity contracts
Ancillary Services	Replacement reserve, regulation up, regulation down, spinning-reserve, non-spinning reserve	Needed to assure system reliability

In its 2004 procurement plan, PG&E identifies a confidential subset of these authorized products that it is likely to use. SCE notes that in addition to the products listed in D.02-10-062, it seeks authority to transact for the following additional products.

Transaction	Description	Benefit/Cost
Structure Transactions	Combine one or more product types, varying expiration dates, tiered prices, etc.	Tailor hedges to match your exposure.
Emissions Credits futures or forwards	Provides right to purchase emissions credits at a fixed price	Hedge exposure to emissions limits resulting from contractual terms.
Weather triggered option	Any transaction otherwise authorized with payment/exercise rights based on weather.	Tailor hedges to match exposure correlated with weather conditions.
Forecast Insurance	Payment to SCE occurs in case of deviations of weather from forecast	Hedges costs resulting from inaccurate forecasts
Gas Purchases	Purchased on a daily basis	Used to hedge fuel cost risk associated with capacity contracts.

We find that these types of transactions are reasonable for SCE's 2004 procurment.

SDG&E's 2004 procurement plan states that last year's table of authorized procurement products includes substantially all of the physical products SDG&E intends to use in its short-term procurement activities. SDG&E explains in detail the types of transactions it wishes to engage in during 2004. In addition to the products that are included on the list from D.02-10-062, are the following:

Transaction	Description	Benefit / Cost
Non-FTR Locational Swaps	SDG&E will have available to it certain resources located outside of the SDG&E service territory that do not have FTR protection. SDG&E may choose not to import the power into SP15 but sell it at the delivery point, purchasing replacement power in SP15 or another location with less congestion risk.	There is some risk of congestion from distant resources without FTR protection. This strategy mitigates that risk. Such open positions would be measured and managed consistent with overall risk management practices.
FTR Locational Swaps	SDG&E owns some FTRs from ZP26 to SP15 via the CAISO2003 FTR auction. When some or all of the FTR capacity is not being used for Sunrise energy deliveries, SDG&E will enter into locational swaps to improve on the initial value of the FTR hedge.	This allows SDG&E to take advantage of the value of its FTRs and reduce overall costs.
Counterparty Sleeves	Two-sided trades where the same product is purchased from one counterparty and sold to another simultaneously.	This helps SDG&E reduce its credit exposure with overexposed parties. It may also reduce SDG&E's costs where it facilitates trades between parties that cannot trade with each other due to credit restrictions.

We find that these types of transactions, though not explicitly accounted for in the list of authorized procurement products included in D.02-10-062, are reasonable for SDG&E's 2004 procurement.

2. Transactional Processes

In D.02-10-062, the Commission authorized the utilities to procure products using the transaction processes listed below.

Transaction Process	Guidelines
Competitive Solicitations (Requests for Offers)	D.02-10-062 set forth guidelines governing the process by which the IOUs shall conduct RFOs. These guidelines are as follows: · Procurement plans shall specify the steps of the solicitation process to be used. The process shall be consistent with the competitive solicitations in use now under transitional procurement authority. · Competitive solicitations may be all-source or may be segmented to allow similar sources to compete with each other, but must cover all of the sources described in section V above. · Solicitations should be widely distributed (starting with bidders list used under transitional procurement authority). Required items shall include among other things: ¬ Description of product requirements ¬ Term ¬ Minimum and maximum bid quantities ¬ Scheduling and delivery attributes ¬ Credit requirements ¬ Pricing attributes · Each utility shall update its procurement plans to specify and describe the evaluation tools and methodology it will use to rank and select bids, such as: ¬ Minimum requirements for counter-party creditworthiness ¬ Minimum number of bids that must be received ¬ An evaluation of cost-to-risk tradeoff (consumer risk tolerance level) of the various bids
Transparent exchanges, such as Bloomberg and Intercontinental Exchange.	· Approved utility plans will identify and describe the various electronic energy trading exchanges that each utility proposes to use (e.g., Bloomberg, Trade Spark, Intercontinental Exchange). · The procurement plans shall demonstrate that the identified electronic trading exchanges the utility intends to use provide transparent prices.
ISO markets: Imbalance Energy, Hour Ahead, and Day Ahead (when operational)	· ISO spot market transactions are authorized to balance system and meet short-term needs. · Procurement plans shall describe procurement strategies for hedging the utility's overall portfolio risk with ISO spot purchases. · While we wish to provide utilities with timing flexibility in meeting their residual net short needs, it is not our intention to have the entire RNS met in the spot market. Though we do not set an explicit limit on spot market purchases, utilities should plan to minimize their spot market exposure and should justify their planned spot market purchases if they exceed 5% of monthly needs. ·We authorize the use of a Day-Ahead Market should it become operational.
Inter-Utility Exchanges	In. D.02-10-062 the Commission provided the following guidance: · Unless we adopt specific guidelines for negotiated IUEs these deals would only occur through an RFO process, which is unlikely to be as successful in price or in meeting specific needs of both parties. By adopting the benchmark and other guidance discussed below we allow negotiated IUEs to be included for approval in the monthly advice letter filings. · The important elements to justify an IUE as reasonable would include: ¬ Cost-effective reductions to seasonal or specific RNS, ¬ Cost effective reductions to seasonal or specific Residual net-long positions. To justify as cost-effective an IUE to reduce RNS (acting as a buyer), the utility will have to demonstrate that at the time of executing the IUE agreement the expected costs for the repayment was less than the avoided incremental costs at the time of delivery. This determination would be based upon the incremental costs of the existing delivery time and repayment time portfolios available when the IUE is negotiated. For example, if the delivery's existing portfolio incremental transaction cost or the most recent RFO bids for the delivery period are more than $100 and if the repayment portfolio's incremental transaction cost was $100 or less then the IUE could be deemed reasonable when filed by advice letter. This total transaction cost would account for the differing values of capacity, energy, ancillary services, and volume of energy in the two sides of the transaction. To justify as cost effective an IUE to reduce residual net long positions (as a seller being repaid in capacity, energy, or ancillary services) the utility would have to demonstrate that the average portfolio value of the time of repayment is higher than the forecast of spot prices when firm energy would otherwise be dumped as surplus into the spot market. (D.02-10-062 ,)
Direct bilateral contracting with counterparties for short-term (i.e., less than 90 days) products	D.02-10-062 authorized such contracting subject to a "strong showing" that these transactions represent a reasonable approximation of what a transparent competitive market would produce. D.02-12-074 added that the strong showing can be met by a "comparison to Requests for Offers completed within a month of the transaction." In D.03-06-067, the Commission waived the "strong showing" standard for negotiated bilaterals for non-standard products procured 31 days or less in advance of delivery and with terms of one-calendar month or less. "Although we waive the strong showing standard for these transactions, the utilities should demonstrate that such transactions are reasonable based on available and relevant market data supporting the transaction. This may include, showing competing price offers, result of market surveys, broker and online quotes, and/or other source of price information such as published indices, historical price information for similar time blocks, and comparison to RFOs completed within one month of the transaction. Additionally, we stated that in instances when a utility knows that it will have a need for non-standard products on a forward and recurring basis, "we strongly encourage the utilities to transact for such products using an RFO process."
Utility Ownership	Utilities may propose to buy or construct generation

The utilities propose to conduct procurement using the same transactional processes listed above in their 2004 procurement plans. SCE's short-term plan also notes that it plans to use (i) Open Access Same-Time Information Systems (OASIS) to procure standard electric transmission products from transmission providers throughout the WECC region at FERC tariffed rates and (ii) voice and on-line brokers, as it did in its approved 2003 procurement plan. SDG&E and PG&E propose to use brokers as well. SDG&E's plan speaks to the use of over-the-counter brokers stating:

"SDG&E includes over-the counter brokers. . .in the definition of exchanges because these firms offer a common mechanism of matching buyers and sellers at the current competitive market price, in concert with electronic exchanges... In addition, there is a high degree of overlap of products and prices offered since counter parties can use electronic exchanges and over-the-counter brokers interchangeably, thus increasing transparency and providing an opportunity for price comparisons." (SDG&E 2004 Short-Term Plan, p. 22.)

We recognize that there may be a pro-competitive effect from broadening our understanding of transparent exchanges to include reputable OTC brokers. We will hold the utilities to the same high standards for transactions consummated through OTC brokers as we do for exchange transactions. That is, the utilities shall demonstrate that the identified OTC brokers provide prices that are equivalent to those of exchanges.

With regards to bilateral contracting, PG&E proposes to expand the use of this transaction process to include products with delivery starting up to six months out. This differs from the authorization we provided in D.02-10-062 where we restricted direct bilateral contracting to short-term products only (i.e., less than 90 days). PG&E does not specify a term length restriction for the expanded bilateral contracting authority it seeks in its 2004 procurement plan.

In explaining the use of bilateral contracts in procurement, PG&E explains that such contracting occurs through private negotiation, through electronic exchanges, and through brokers. In support of expanding the authorized use of bilateral contracting, PG&E explains that bilateral contracting is preferred over competitive solicitations for a number of reasons, including: (1) use of competitive bid processes limits PG&E's price discovery; (2) the competitive bid process has potentially high transaction costs for both buyers and sellers and this can limit the number of parties participating in an RFO process; (3) RFOs may require bidders to hold prices open for an extended period of time while the process unfolds, thereby increasing prices; (4) competitive solicitations typically take several months to complete; (5) limiting transactions to only competitive solicitations can lead to market power because bidders will know the utility has limited alternatives to execute transactions; (6) utilities outside of California are the most likely counterparties for inter-utility exchanges; and (7) the financial duress besetting many counterparties in the WECC region may limit the role of marketers. Finally, PG&E states:

"If all products greater than three months' duration, or to be delivered three months out, were transacted via a competitive bid process, PG&E would be frequently issuing RFO/RFP up to two months before actual delivery, a costly and impractical proposition. Hence, PG&E necessarily relies more frequently on bilateral contracting for products with delivery starting up to six months out." (2004 short-term plan, PG&E, p.4A-3, 4.)

SCE seeks to expand the use of bilateral contracting as well, specifically for negotiated bilaterals as opposed to brokers and exchanges. For negotiated bilaterals, SCE requests authority to transact for products up to five years in term. SCE conditions this expansion of bilateral authority in instances where "five counterparties or fewer can supply the service or enter into a particular transaction (this may occur, for instance, when purchasing natural gas storage or pipeline capacity). SCE also proposes that physical gas bilateral transactions be authorized for up to [five years] if the pricing for such a transaction is index linked." (SCE 2004 Short-term plan, p. 128.)

SDG&E likewise proposes to use negotiated bilaterals, particularly for non-standard products, but does not specify a term length restriction.

With the exception of ORA objecting to SCE incorporating a five-year horizon under its 2004 short-term plan, no party voiced opposition to these bilateral contracting proposals. We discuss this request for authority in relation to the cost-effectiveness testing for transactions and benchmarks proposed for each type of transaction, as discussed below.

3. Cost-Effectiveness Testing for Transactions & Benchmarks

ORA, PG&E and SCE each propose modifications to the transaction selection protocols adopted in the 2003 short-term procurement plans.

a) ORA's Proposal

In its June 23, 2003 direct testimony, ORA requests that the Commission approve a procurement process for use by PG&E, SCE, and SDG&E. The process, as proposed by ORA, is as follows:

1. Define scenarios or model inputs;

2. Weight scenarios or model inputs;

3. Establish other input assumptions;

4. Establish candidate products that would be effective given particular stress scenarios or other model results;

5. Solicit hedge products;

6. Share bids with PRG;

7. Evaluate candidate hedges and rank according to cost-benefit analysis;

8. Meet with the PRG and solicit comments from PRG members and attempt to reach a consensus;

9. Tentatively select hedges;

10. Update TeVaR to reflect the addition of the new candidate hedges; and

11. Select hedges.

The 11-step process outlined above is consistent with the procurement process proposed by PG&E in its 2004 procurement plan with the exception that ORA has inserted several steps for utility consultation with its PRG. We also note that ORA's 11-step procurement process generally reflects the procurement process that each utility employed in 2003 for competitive solicitations.

The issue of how often this process should be used by the utilities was raised by SCE during hearing when it pointed out that the utility typically enters into between 20,000 and 50,000 transactions a year. SCE implied that the process would be too cumbersome and unwieldy for all procurement transactions given the large volume of transactions the utility conducts per year. ORA clarified on cross-examination that it does not advocate use of its proposed process for spot-market transactions, one-week-ahead transactions, and prompt-month transactions (transactions executed one calendar month prior to the month of delivery).

b) PG&E's Proposal

PG&E proposes price benchmarks for the various procurement products it seeks to transact for under its 2004 short-term plan. For transactions of real-time energy and ancillary service from ISO markets, PG&E proposes that ISO settlement prices should serve as the benchmark given that ISO markets are the only markets for such products. For standard procurement products, PG&E essentially proposes to use "available and relevant market data, including price quotes from counterparties, brokers, and electronic exchanges, forward curves developed by PG&E and/or third parties, and published indices, supplemented by online price information from news services like Bloomberg and Reuters." {PG&E short-term plan, p. 4A-4} For non-standard spot market transactions in the day-ahead and hour-ahead markets, when there is no relevant market information, PG&E proposes to demonstrate that these transactions are reasonable based on the need for the products and to document how these non-standard products "were evaluated and adjusted in value compared to more visible price benchmarks." (p. 4A-4)

PG&E further states that in situations where no relevant market data exists to establish a benchmark, PG&E will seek the concurrence of its PRG to go forward with the transaction based on a benefit/cost test pre-agreed with the PRG.

ORA does not challenge PG&E's proposed benchmarks for real-time energy and ancillary services procured from ISO markets. With respect to other product benchmarks ORA recommends that the Commission reject these benchmarks finding that they are incomplete, oversimplified, and lacking definition. Additionally, as discussed in more detail in Section the previous section addressing ORA's proposed 11-step procurement process, ORA objects to PG&E's proposal to use a pre-approved benefit/cost transaction test.

We note that although PG&E did not advance specific benchmarks in its procurement testimony, in its PG&E's 2004 Energy Resource Recovery Account testimony, filed August 1, 2003, PG&E presents numerous specific benchmarks for electricity products. We summarize those benchmarks below by transaction term.

Term Transaction

Forward: Prompt-month or longer

Term: 21 days or longer.

Index: Calculated by averaging end of trading day forward prices for the appropriate product (on-peak or off-peak), location (COB, NP15, SP15), time frame (month or quarter), and transaction date of Brokers (Amerex, Natsource, ICE, Prebon and TFS).

Balance of Month Transaction

Forward: Current month or next month

Term: less than 21 days, > 14 days

Index: Calculated by averaging the end of trading day forward prices for the appropriate product (on-peak or off-peak or flat), location (COB, NP15, SP15), month, and transaction date of Brokers.

Day Ahead Transaction

Forward: Transactions for the next one, two or three days (according to ISO scheduling protocols)

Term: One day

Index: Calculated by averaging the index for the appropriate product (on-peak or off-peak or flat), location (COB, NP15, SP15), month, and transaction date of Brokers.

Hour Ahead Transaction

Forward: HA Market, current month or next month forward

Term: less than 24 hours.

Index: Developed using Dow Jones Hour Ahead indices, which are currently the only publicly available HA indices. The HA indices for some hours at COB and SP15, and all hours at NP15 were estimated, as there is no published NP15 HA index and hourly price data for COB and SP15 are spotty. For COB: the COB HA index was used when available; when there was not a Dow Jones published index for COB for a given day, the hourly Dow Jones MidC index was used with an adder based on the DA COB/MidC spread. For NP15: when a COB hourly index was available it was used with an adder based on the NP15/COB DA spread (on-peak or off-peak hours as appropriate). If a COB index was not available, the SP15 hourly index was used when available with an adder based on NP15/SP15 spread (on-peak or off-peak hours as appropriate). If neither the COB nor the SP15 hourly index was available, the MidC hourly index was used with the DA on-peak or off-peak NP15/MidC spread. For SP15: the SP15 HA index was used when available, when there was not a Dow Jones published index for SP15 for a given day, the hourly Dow Jones Palo Verde (PV) index was used with an adder based on the DA SP15/PV spread. If neither the SP15 nor the PV index was available, the calculated NP15 hourly index was used with the DA on-peak or off-peak SP15/NP15 spread.

c) SCE's Proposal

In its 2003 adopted plan, SCE established a benchmark for all transactions that the Risk Hedged (RH) divided by the Cost of the Hedge (COH) must be greater than a confidentially specified value. In its 2004 filing, SCE does not propose to use this risk screening criteria. Instead, SCE states that no risk screening criteria should be applied to transactions extending X (confidential) years or less, and that for those extending more than X years, the prospective transaction must reduce portfolio risk. SCE's requirement from its 2003 procurement plan that transaction timing and volume policy mitigate price risk has been eliminated from its 2004 plan.

We find SCE's proposal to not apply a risk screening criteria to transactions of less than a certain length to be in contravention of AB 57, which requires utilities to optimize portfolio value, regardless of the maturity of the transaction. SCE should retain its existing standard for its 2004 plan.

d) SDG&E's

SDG&E's 2004 plan asserts that its proposed trading methods meet the criteria for reasonableness. Regarding its proposed use of bilateral contracts, the Company asserts:

Prior to executing such an [sic] structured transaction, SDG&E would (1) compare the economic and operational benefits to its associated premium over dispatching a CDWR contract and against purchasing a standard energy product valued against the forward prices covering the same period of delivery, and (2) demonstrate that the product benefits the overall portfolio by reducing net cost or customer VaR. This meets the criteria for bilateral contracts set forth in Section VI.E. of D.02-10-062 and these transactions should therefore be deemed reasonable.¹¹⁴

SDG&E also asserts in its 2004 plan that all transactions entered into through use of transparent exchanges and brokers should be deemed reasonable, as should its proposed use of spot markets, competitive solicitations, and purchases of reserves and other ancillary services, all of which will be completed in a manner meeting the criteria established in D.02-10-062.

4. Discussion

For the 2004 short-term plans, we authorize the utilities to conduct procurement using the following transactional methods:

1. Competitive Solicitations (RFOs/RFPs)

2. Electronic exchanges and voice and online-brokers

3. ISO Markets

4. Inter-utility Exchanges

5. Negotiated Bilateral Contracting as defined and limited below

6. Open Access Same-Time Information Systems (OASIS) sites

We adopt the 11-step procurement process proposed by ORA as the standard procurement process to be used by PG&E, SCE, and SDG&E. This process is to be used in that small minority of the total number of transactions where there is substantial value and risk. As discussed below, for the great multitude of transactions, the 11-step procurement process is not helpful and is too burdensome. The exceptions are discussed below.

Recognizing that this process is not appropriate for all procurement transacting, we provide exceptions to this process as discussed below. The 11-step process is best suited for procurement transactions that are developed and planned over a long period, such as transactions that are entered into on a multi-month forward basis, long-term PPAs, acquisition of generating resources, or other significant contracting efforts involving competitive solicitations (i.e., Requests for Offers). Such transactions are likely to involve more planning cost and they embody more risk. With respect to negotiated bilateral agreements, we do not authorize such contracting except as provided below.

For short-term transactions (i.e., less than 90 days in term) executed within a 90-day window prior to delivery, the IOUs are not required to employ the 11-step process. Given the speed by which transacting occurs during this short-term time period, we find that the 11-step process would be too unwieldy to apply, particularly given the enormous number of transaction that the IOUs typically transact for during this timeframe.

We grant authority for the use of negotiated bilateral in three limited circumstances only. First, for short-term transactions of less than 90 days duration and less than 90 days forward, the IOUs are authorized to continue to use negotiated bilaterals subject to the strong showing standard we adopted in D.02-10-062, as modified by D.03-06-067. Any such negotiated bilateral transactions shall be separately reported in the utilities quarterly compliance filings.

Second, utilities may use negotiated bilateral contracts to purchase longer term non-standard products by including a statement in quarterly compliance filings justify the need for a non-standard product in each case. The justification must state why a standard product that could have been purchased through a more open and transparent process was not in the best interest of ratepayers.

We are receptive to expanding the use of negotiated bilaterals for standard products in instances where there are five or fewer counterparties who can supply the product, as suggested by SCE. We limit this authority, however, only to the two categories of gas products cited by SCE: gas storage and pipeline capacity. In such instances, the utility needs to affirm that five or fewer counterparties in the relevant market offered the needed product. Any resulting contract shall be separately reported in the utilities' quarterly compliance filings

In D.02-10-062, we restricted the use of "direct bilateral contracting." Our purpose in limiting the use of such contracting was to (i) prevent a situation from arising where utilities would conduct substantial levels of procurement through private negotiated deal-making as opposed to through processes involving greater price transparency and competition while at the same time (ii) providing the utilities with transaction flexibility to procure near-term and short-term products (including non-standard products) necessary for system balancing and reliability purposes without burdening the utility with a competitive bid process. In limiting the use of negotiated bilaterals, we also sought to promote procurement transaction transparency given the restriction in Pub. Util. Code § 454.5(d)(2) on ex-post reasonableness reviews of a utility's procurement activities and given the Legislative intent of AB 57 for the Commission to approve procurement plans that employ the use of competitive procurement processes.

PG&E articulates a number of significant points regarding the use of negotiated bilaterals, but other than stating that such contracting would be conducted for products with delivery up to six months out, it does not propose any restrictions or parameters delineating how much of its procurement would be secured through negotiated deal-making. If we adopted PG&E's request, would a utility seek to conduct most or nearly all of its procurement up to six months out through a series of negotiated bilateral agreements? This remains our concern. Pending the development and adoption of a procurement incentive mechanism, we authorize the utilities to pursue negotiated bilaterals subject to the restrictions outline above. We stop short of adopting PG&E's proposal until a showing is substantiated that such bilateral contracting will not become the default transactional process for all products with delivery up to six months out.

Lastly, we note that PG&E did not identify the electronic energy trading exchanges and brokerages that is proposes to use under its 2004 short-term plan. In its re-filed, short-term plan, PG&E should include such a list.

E. Fuel and Power Forecasts

ORA and TURN both note that SCE and SDG&E gas price forecasts did not include near term gas prices, and this factor may affect the accuracy of the conclusions. ORA recommends that the utilities should use consistent fuel price forecasts in both short-term and long-term resource planning. ORA also recommends that near term gas prices should always be incorporated or used to supplement testimony in future procurement planning proceedings. TURN argues that the IOUs' fuel and price forecasts are already outdated, jeopardizing the value of the analyses contained in their resource plans. TURN adds that actual gas and electric market prices reported for June 2003 were approximately equal to the "90 percent high" levels of the IOU probability distributions for future Junes starting in 2007.

Discussion

While it is our expectation that the IOUs use the best available data in preparing analyses, it is an eternal truth that forecasts are quickly outdated. We cannot fault the utilities for relying on forecasts that did not anticipate this spring's run up in gas prices. And we note that since the spring, prices have declined. If anything, the facts that TURN and ORA present support a different conclusion: it may be that gas price forecasts upon which the utilities depend underestimate the degree of price volatility in gas markets. Perhaps the distribution of future gas prices is wider than anticipated by current forecasters. Though the forecasters may have the long-term trends right, the amount of price variability around those trends may be greater than has been thought up to now. For future filings, we expect the utilities to use their best effort to obtain up-to-date forecasts, and also to estimate appropriately the high and low cases surrounding those forecasts. Additionally, we note that as part of its 2004 procurement plan, PG&E proposes to update its plan on a quarterly basis to reflect changes to its open position and to relevant market prices. We find that it is appropriate for each of the utilities to review market conditions relative to fuel forecasts on a quarterly basis with its PRG and to file plan updates if the plan does not adequately capture current market conditions. Finally, we note that given the fact that seven months have elapsed since the utilities filed their short-term procurement plans on May 15, 2003, each IOU shall update its within 5 days from the effective date of this decision to reflect changes to fuel prices forecasts and open positions.

F. Role of PRG

In D.02-08-071, the Commission approved the joint request of SCE, PG&E, TURN and the Consumers Union to create utility-specific Procurement Review Groups (PRGs) comprised of eligible non-market participants. In D.02-10-062, the Commission approved the continuation of the PRGs for 2003. The concept of a Procurement Review Group (PRG) was first formally proposed as part of SCE's May 6, 2002 filing of its motion for Capacity Procurement. In this filing, SCE stated that the PRG is a "Commission-authorized entity whose members, subject to an appropriate non-disclosure agreement, would have the right to consult with and review"¹¹⁵ the confidential details of IOU procurement activity. The PRG would assess procurement activity and upfront reasonableness criteria and offer assessments and recommendations to the IOU when contracts are submitted for Commission review. Following this filing, SCE drafted a memo entitled Joint Principles for Interim Procurement. The three IOUs, TURN and the Consumers Union (CU) are signatories to these Principles. A Procurement Contract Review Process was established, endorsed by the PUC, and incorporated as Appendix B to D.02-08-071.

Each IOU's 2004 procurement proposal is based on the assumption that the PRG process will continue into 2004, and that there will be regular IOU-PRG consultations on proposed procurement and hedging activities. ORA and TURN also support continuation of the PRG in 2004. As TURN states:

"The creation of the PRGs constitutes an innovative effort to involve utilities, consumers and state agencies in a forward-looking dialogue before formal filings are submitted for Commission approval. The impetus behind the formation of the PRGs - the switch to up-front approval standards under AB 57 - remains relevant for the foreseeable future."

As a key element of its long-term procurement policy, the Commission will be establishing an incentive mechanism and/or upfront standards and criteria to augment the PRG process. Should the PRG "sunset" this year, and without elements of our long-term policy in place, there would be no pre-defined forum in which utilities could inform the Commission and non-market participants of their day-to-day risk management concerns and objectives.

If the PRG were to "sunset" at the end of 2003, PG&E has stated that as a default, it would pursue an on-going, informal dialogue with ORA and other non-market parties regarding proposed procurement and hedging activity¹¹⁶. We note, however, that in the absence of a PRG process, this consultation would be strictly ad-hoc and at the discretion of the utilities.

SCE witness Kevin Cini testified during the hearing that, "...I actually think that the PRG process provides more visibility to the Commission and the parties that have access to SCE confidential information than if we had some other process in place."¹¹⁷ Mr. Cini goes on to say, "Our procurement plan contemplates the PRG continuing to 2004. The PRG is an integral part of our procurement plan."..."we would still want to work with the consumer advocates in an informal way, where we would still share with them business issues that we have....and we would share with them the models that we're considering using to get their feedback on that..."

Though it only has consultative and informal advisory functions, the Commission finds the PRG to be an effective vehicle for IOU dialogue with Commission staff familiar with the nuances of their energy portfolios and the necessary policies/strategies needed to mitigate portfolio risks. The PRG has played a valuable role in identifying potential issues or concerns regarding IOU procurement. Perhaps the most significant achievement of the PRG process since its inception is the reduction of contested or litigated procurement transactions. As stated by TURN in its closing brief:

"Many of TURN's suggestions have been incorporated into procurement activities without the need for time-consuming and combative litigation. As result, the amount of actual litigation associated with individual transactions and strategies has been limited to a few isolated disagreements . . . ." (p. 38.)

PRG members have sufficient access and dialogue with the utilities, that they can advise utilities of potentially contentious issues or procurement activities prior to the utility executing a trade. The value of this collaborative process is accurately portrayed by TURN in its closing brief:

"Without a PRG structure, TURN and other non-market participants would be denied the opportunity to learn about ongoing activities and challenges in real-time and instead would be forced to review materials underlying the Advice Letter filings for the first time after the decisions had been made and submitted for approval." (p. 39.)

We find that it is beneficial to continue the PRG process. As provided for in D.02-10-062, each utility shall meet and confer with its PRG on a quarterly basis. Each PRG has the option of conducting meetings by teleconference. When PRG meetings are conducted by teleconference, we urge each utility to provide electronic copies of meeting materials to PRG members in advance of the meeting, and to provide adequate time for review of such materials prior to the meeting. During the quarterly meetings, each utility shall review with its PRG the utility's open position, changes in market conditions from the previous quarter, including gas and electric prices, hedging strategies going forward, and the necessity of filing a plan update. PRG meetings may be held for often than quarterly under circumstances when portfolio risk exceeds the CRT as described in Section 5.C.1. of this decision.

Even with an incentive mechanism and upfront standards and criteria in place in place, the PRG can serve as a "streamlining" entity, interfacing with utilities and helping to facilitate utility filings at the Commission, thereby making the filing process more efficient. The PRG structure allows for substantive review of and input to time-sensitive procurement and risk management proposals, since PRG members (including Energy Division staff) have advance access to the large volume of data and market information inherent in procurement report filings.

The Commission is proposing a long-term risk management framework in which the role/process of the PRG would still be useful, though not as vital. The PRG would not be obsolete, but could continue to serve as an advisory/consultative group to the utilities. Further, PRG members now have knowledge and experience with the utilities' risk management and procurement practices, and most would likely participate in negotiating with the IOUs to develop the incentive mechanism, one of the main elements of our long-term risk management policy. The PRG could alert the Commission if there are concerns or if issues arise as a result of the utilities' procurement activity.

In response to a memo from DWR, we note that the PRG's role is an advisory one, and it does not preclude DWR's authority to conduct a reasonableness review. The Commission has recognized this authority, and now reiterates its recognition of Article 4.2 of the Rate Agreement, which stipulates DWR's authority to determine just and reasonable costs, as per its reasonableness review.

G. Modification and Approval of Short-Term Plans

In its short-term plan, SCE does not use the pro-rata cost allocation of DWR contracts that the Commission adopted in D.02-09-053 and confirmed in D.02-12-045 and D.02-12-069; it should amend its plan to comply with this requirement.

PG&E requests the Commission relieve it of its responsibilities to manage gas hedging for its allocated DWR contracts in the event it does not have sufficient credit capacity to enter into such hedges given the other demands for its limited credit capacity. We deny PG&E's request here. PG&E's responsibilities are set forth in its Operating Agreement with DWR and any changes to that agreement must be done through negotiations with DWR and/or a petition to modify D.03-04-029.

PG&E requests the Commission extend the disallowance cap we adopted in D.03-06-067 to the 2004 short-term plans. We should do this, and on the same terms as we adopted in D.03-06-067, and confirmed in D.03-06-076 and D.03-10-090. We do not entertain PG&E's request to extend the scope of the disallowance cap as we have previously addressed this issue in the above mentioned decisions.

Each utility should file by advice letter within 15 days a revised short-term plan that conforms to this decision. These plans shall conform to all Commission decisions unless specific findings are made here to change a previous Commission decision.