III. 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. Further direction regarding incentive mechanisms will be forthcoming early in 2004 as part of our upcoming policy decision on long-term procurement planning. Our review of each utility's STPP 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 with delivery beginning in 2004, 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.⁵

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 conduct 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. Appropriate Short-Term Reserve Levels and Reliance on Spot Market Purchases

The Joint Recommendation proposes that, for 2004 only, the utilities will provide reliable service by procuring sufficient resources to ensure that they meet their peak demand plus an appropriate operating reserve margin. The level of the operating reserve margin is determined by the Western Electricity Coordinating Council (WECC) and is approximately 7% of peak demand.⁶

The Joint Recommendation proposes that the "operating reserve margin" (ORM): ⁷

Shall be used for purposes of reviewing resource adequacy over a shorter term, such as a year or less and shall be applicable to STPPs. ORM is computed as follows: ORM = ( ( (Dependable Capacity - Reasonably Expected Resource Outages)/Peak Load) - 1) x 100%.

Based on the record developed in this proceeding, we adopt the Joint Recommendation's proposal for 2004 only while the Commission develops its long-term policy on appropriate reserve levels and the types of resources capable of meeting these reserve level obligations.

In adopting this level we emphasize the importance that this Commission places on ensuring that the utilities' procurement plans provide reliable service.

Additionally, although several parties were opposed to the Joint Recommendation's proposal that each utility only meet the ISO's proposed 7% operating reserve requirement for 2004, a closer look at the utilities' filings shows that their actual planning reserve margins for 2004 were significantly above the 7% minimum. SDG&E's testimony, for example, showed that it possessed sufficient capacity, either owned or under contract, to easily meet the 7% operating reserve requirement, implying that SDG&E's actual planning reserve levels were well above 7%. A review of SCE's filing shows that, in determining its resource needs, it had already included in its calculation estimates of expected plant availability (a major component of a planning reserve level) as well as excluding its interruptible load programs in calculating its reserve level. Thus, SCE's actual planning reserve margin would appear to be significantly higher (perhaps in the 12-13% range) for 2004. Only for PG&E does it appear that there might be some over-reliance on spot purchases, but again PG&E's original filing did not include its subsequent procurement efforts (approved by the Commission) to firm up a significant portion of its outstanding short position.⁸

With respect to the utilities' reliance on spot market purchases, in D.02-10-062 the Commission provided the following guidance:

"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 market 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."⁹

We find that this is a reasonable guideline or precept to continue in the utilities' STPPs. We clarify that this guideline applies to energy procurement in Day-Ahead, Hour-Ahead, and Real-Time markets and it is intended to represent a target amount, rather than a hard limit, as there may be economic reasons justifying a utility's decision to exceed the target (i.e., least-cost dispatch). We also find that this guideline provides an appropriate balance between procurement flexibility and reliability.

C. Review of Risk Management and Reporting Proposals

Our discussion here will focus on (1) refinements to risk management and reporting that 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. Portfolio Risk Measurement

In the 2003 short-term plans adopted last year, each utility proposed its own tools and framework to measure portfolio risk. In D.02-12-074 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 were not prescriptive at that time in requiring the use of the Value at Risk (VaR) or Cash-Flow-at-Risk (CFAR) models - the models recommended by ORA. 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 short-term plans, 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.¹⁰ SCE states it can report portfolio risk 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."¹¹ 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. On cross-examination, SCE's witness testified that the utility would be willing to have the model validated by an independent source. Model validation will confirm that the criteria of transparency, accuracy, and standardization in risk reporting that the Commission requires are met. SCE indicates that it will share the results of its in-house model with Commission staff and the PRG before using the model.

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 methodology models and recommends that the utilities' portfolio risk measurement modeling efforts should specifically focus on the concept of "Ratepayer Cost at Risk" (RCaR). According to TURN, RCaR represents the risks that bundled ratepayers face of paying higher rates. Based on its review of the utilities risk measurement proposals, TURN concludes "that the investor-owned utilities (IOUs) are already attempting to implement such a standard."¹²

Public Utilities Code 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." Standardized risk reporting will ensure that the Commission's procurement and risk management policies address the concerns of all ratepayers in an equitable and unbiased manner, regardless of utility provider. The Commission has a duty to ratepayers to ensure that this price assessment is conducted in a consistent manner, with appropriate standards of transparency inherent in and equivalent to 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 also note that SCE recently (in November 2003) briefed Commission staff and the PRG on the results of its model development efforts.

We believe that portfolio risk should 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. It was developed to respond to the demands of upper management who wanted a quick and succinct "snapshot" of the worst-case scenario for portfolio loss or exposure. ORA testifies that all of the IOUs' holding companies indicate in their 2002 Annual Reports that they use a VaR model. The commercial viability and acceptance of VaR and other commercially available risk methodologies provides the Commission with confidence that such models yield 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)."¹³

While we continue to believe that it is unwise to be overly prescriptive 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. We recognize 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. Establishing a common benchmark is one way of ensuring 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.

Given the timeline of SCE's model development efforts, we adopt here the provisional use of SCE's model pending verification. To initiate the verification effort, SCE shall submit a model report to Energy Division staff, describing the methodology, assumptions, and formulas of the model. When SCE submits this report, it indicates that the model is in final form. Following the submittal of the model report, SCE and Energy Division staff will discuss elements of the validation process, such as selecting the independent auditor, scope of the audit, and the methodology for model validation. An unqualified model certification will serve as the basis for authorizing the model. In the event that the model is not successfully validated, SCE and Energy Division staff will agree on the use of a commercially available risk measurement model. Cost recovery for this validated model shall be sought through the General Rate Case (GRC) process, the same as all procurement administration expenses. We authorize PG&E and SDG&E to use the TeVaR methodologies proposed in their short-term plans.

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. In essence, the 95^th percentile presents the 1 in 20 outcome. Costs above this level are expected to occur on fewer than 1 in 20 occasions. 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 percentile as the standard for managing its portfolio within the Consumer Risk Tolerance (CRT). The 99^th percentile presents the 1 in 100 outcome. Costs above the 99^th percentile are expected to occur less than once in a hundred occasions.

We believe risk reporting should serve as a "roadmap," alerting the Commission of the relative risk in different time periods. At a 95^th percentile, we would be aware of the costs associated with a 1 in 20 possibility, but not the more remote or extreme possible outcomes. In D.02-12-074, we directed the utilities to consult with their PRGs when measured portfolio risk exceeds 125% of the adopted CRT. Based on this protocol, IOUs called a PRG meeting on two occasions to discuss the risk drivers accounting for the upward swing in portfolio risk (SDG&E on February 25, 2003 and PG&E on March 5, 2003).

We find that a 99^th percentile reporting will provide additional price volatility information and should not be burdensome to the IOUs or to the PRGs. We are guided by TURN's testimony that our risk management standards should seek to protect bundled ratepayers against highly unlikely events. While we do not adopt PG&E's additional stress scenario proposal (as a complement to TeVaR measurement) as a requirement, there may be instances, e.g., the gas price run-up earlier this year, where this type of analysis is prudent and we encourage each utility to perform any additional scenario analysis it believes is warranted and to discuss this information with its PRG. With respect to portfolio risk notification, we adopt PG&E's proposal for use by each IOU, endorsed by ORA, with modifications:

1. If between quarterly PRG consultations, a utility's estimated portfolio risk (measured at the 99^th percentile) exceeds 125% of the CRT, the utility will promptly meet and confer with its PRG to discuss the underlying risk drivers and factors affecting the change in portfolio risk and to decide whether specific hedging strategies and/or plan modifications are needed to reduce portfolio risk to within the CRT threshold.

2. If the utility and the PRG decide that plan modifications are needed, the utility will file these modifications in the form of an expedited application, within 15 days of the PRG meeting.

3. Until the application is approved, the utility may operate under its existing plan.

Therefore, we adopt risk reporting using a by-product of VaR (TeVaR), measured on a 12-month rolling basis, at a 99 percent confidence level. We order the utilities to file a monthly portfolio risk report with the Commission's Energy Division. Beginning in 2004, the monthly reports should reflect an estimate of portfolio risk for each month on a rolling 12 month basis, on a quarterly basis for months 13-24, and on an annual basis for months 25-60.

2. Risk Management

In Assembly Bill (AB) 57, Section 1(d), the Legislature:

"Directs the Public Utilities Commission to assure that each electrical corporation optimizes the value of its overall supply portfolio, including Department of Water Resources contracts and procurement pursuant to Section 454.5 of the Public Utilities Code, for the benefit of its bundled service customers."

In implementing Pub. Util. Code § 454.5, the Commission is required to (1) assess the price risk associated with each utility's portfolio; (2) ensure the utility has moderated its price risk; and (3) ensure the adopted procurement plan provides for just and reasonable rates, with an appropriate balancing of price stability and price level. (Sections 454.5(b)(1), 454.5(d)(4), and 454.5(d)(5).)

The manner in which each utility identifies and manages price risk, and optimizes the value of its overall supply portfolio for the benefit of its bundled service customers is the risk management function. The Commission has three primary oversight responsibilities in its short-term risk management policy: (1) specify the interim level of consumer risk tolerance that the utilities should use in managing their short-term procurement portfolios; (2) make sure each IOU has accurate and transparent tools in place to measure ratepayer risk exposure; and (3) review and adopt utility procurement plans. We address here consumer risk tolerance.

(a) Consumer Risk Tolerance (CRT)

In D.02-10-062, we defined CRT as "the price that an average consumer would be willing to pay to reduce the risk of higher prices in the future" (i.e., the cost-to-risk tradeoff), discussed its importance in setting the limits of potential price risk under which each utility should manage its procurement portfolio, directed the Energy Division to retain a consultant to gather additional information regarding appropriate CRT levels, and requested parties to propose an interim CRT.

In D.02-12-074, we adopted an interim CRT level and notification protocol based on modifications to proposals advanced by ORA and TURN. While PG&E and SDG&E filed CRT proposals in their modified 2003 plans, SCE did not. SCE's interpretation of the CRT protocol that was outlined in Confidential Appendix C to D.02-12-074 led it to later file a petition to modify D.02-12-074, which we addressed in D.03-06-076.¹⁴

At present, each utility implements the CRT slightly differently. PG&E is the only utility to publicly discuss the specifics:

"PG&E currently manages the electric portfolio recognizing a consumer risk tolerance of one-cent per kWh, assumed to apply to a potential rate increase of one-cent per kWh over a one-year period. This translates to a risk tolerance level of about (confidential number). PG&E's approved 2003 Procurement Plan also established a notification limit to the Commission when portfolio exposure reached 125 percent of this risk tolerance." (Exhibit 26, p. 3-2.)

As a result of budget uncertainties, the consultant study authorized under Section 454.5(f) has been delayed. Energy Division plans to consult with each utility in the first quarter of 2004 and then prepare a draft scope of work for comment by all parties. A final consultant's report should be served on all parties for comment and the consultant made available as a witness if requested by the Commission.

For 2004, the utilities should continue to use the interim CRT adopted in D.02-12-074 as well as the risk notification protocol described in Section III.C.1. of the decision.

D. Authorized Contract Term Duration and Volume Limits

The PG&E and SDG&E short-term plans focus on implementing the first-year (2004) of their respective long-term plans whereas SCE's short-term plan covers the period 2004-2008. With respect to contract term authorization, PG&E proposes to transact for contracts of up to one-year in term due to its bankruptcy status. We address PG&E's credit concerns as they relate to procurement in Section III.F. SDG&E and SCE do not propose contract term authority beyond the five-year term duration we authorized in D.02-10-062 for the 2003 short-term plans.¹⁵ We agree that utilities should not limit their procurement exclusively to contracts with terms of one year or less. Therefore, as part of our approval of short-term plans, we authorize the utilities to enter into contracts with terms up to five years for transactions to meet 2004 needs with delivery beginning in 2004.¹⁶ Though SCE presented a five-year procurement plan extending to 2008, we do not authorize forward contracting for products with delivery scheduled to begin after 2004. We also emphasize that in continuing the five-year contracting authority granted in D.02-10-062, it is our strong expectation that the utilities shall not lock-in resources that would preclude Commission action in the long-term phase of this proceeding for the preferred resources identified in the "loading order" of the Energy Action Plan (EAP).

With respect to the identified need for physical products, based on our review of the utilities' short-term plans and parties' comments on these plans, we find the volumetric limits/position targets submitted by PG&E, SCE SDG&E to be reasonable.

E. Upfront Standards for Utility Procurement Products and Transactions

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.

3. 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.

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 procurement.

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.

4. 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.

PG&E proposes to expand the use of bilateral contracting 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. 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.

5. Affiliate Transactions

In last year's hearings, the Commission considered the issue of transactions with affiliates at considerable length. The assigned Commissioner ruled in the April 2, 2002 Scoping Memo that there should be no transactions with any affiliates of the respondent utilities, not just their own affiliates.

Several parties objected to this broad prohibition in their testimony, stating that this would deprive California of a significant source of generation. Parties that supported a prohibition on affiliate transactions supported only the narrower prohibition of a utility purchasing from its own affiliates. TURN, Aglet, and the Consumers Union submitted testimony and comments discussing the risks inherent in allowing utilities to buy power from their own affiliates within the current holding company structure.

During the hearings, the Commission requested each utility to prepare an exhibit showing electric procurement disallowances made by the Commission during the 17-year period from 1980 to 1996. These exhibits show that there were only a limited number of disallowance decisions in that period, and that the majority of these decisions and dollar adjustments involved affiliate transactions. Recognizing this, and that the current affiliate transaction rules adopted in 1997 were not designed for today's market structure, the Commission adopted a moratorium on PG&E, SCE and SD&E dealing with their own affiliates in procurement transactions, beginning January 1, 2003, to allow for a careful reexamination and appropriate modification of our affiliate rules.¹⁷ (D.02-10-062, page 49.) We also adopted permanent minimum standards of behavior for the respondent utilities, Standard 1 being:

"Each utility must conduct all procurement through a competitive process with only arms-length transactions. Transactions involving any self-dealing to the benefit of the utility or an affiliate, directly or indirectly, including transactions involving an unaffiliated third party, are prohibited."

In applications for rehearing of D.02-10-062 and D.02-12-074, PG&E and Sempra Energy (Sempra) challenged the moratorium on affiliate transactions, and SDG&E and Sempra challenged Standard of Behavior #1. In D.03-06-076, the Commission found that the ban on affiliate transactions was properly noticed, jurisdictional, constitutional, violated no federal laws, and the record supported the need for a moratorium on utility procurement from its own affiliates until adequate safeguards are fashioned. Further, the decision states that the issue of adequate safeguards against affiliate abuses in energy procurement is an extremely important issue that can be addressed in the long-term procurement phase of this proceeding or in R.01-01-011.

D.03-06-076 also sustained Standard of Behavior 1 and provided the following clarification:

"Standard 1 does not preclude the IOUs from entering into `anonymous' transactions through approved interstate brokers and exchanges, provided that the solicitation/bidding process is structured so that the identity of the seller is not known to the buyer until agreement is reached, and vice-versa. Under these circumstances, the risk of affiliate transaction abuses is minimal. It is our understanding that most, if not all, of the brokers and exchanges being used by the IOUs already structure the bidding so that it is anonymous. Thus, this standard imposes little, if any, burden on interstate commerce."

In this proceeding parties have provided testimony and briefs on the merits of the existing moratorium, as well as potential changes, including the issue of utility ownership of new generation; the merits of having different affiliate rules for short-term and long-term transactions; and whether certain of PG&E's and SDG&E's dealings with other departments within their companies and with affiliates merit specific attention by this Commission.

Today's decision does not explicitly address this testimony and briefing, but reserves the issue of modifications to the existing affiliate ban to the upcoming policy decision. Until that decision issues, the parties must abide by the status quo, and conform their conduct to the requirements of D.02-10-062 and D.03-06-076.

6. Cost-Effectiveness Testing for Transactions & Benchmarks

ORA, PG&E and SCE each propose modifications to the transaction selection protocols adopted in the 2003 STPPs.

(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."¹⁸ 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."¹⁹

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 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 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.

⁶ As the Joint Recommendations states, the level of operating reserve was last "...defined in the April 2003 WECC Minimum Operating Reliability Criteria ("MORC"). MORC includes "contingency reserves," which is capacity needed to cover the greater of the largest single generation or transmission contingency, or 5% of the load met by hydro generation plus 7% of the load met by thermal generation. "