SCE's adopted 2003 STPP provided a complex screening system for long-term and non-standard products. However, for standard products and short-term transactions, the STPP provided a less complex methodology. In its proposed 2004 STPP, SCE presents a similar set of tools and methodologies to evaluate non-standard products for its portfolio, and again states that the method for evaluating standard products and short-term products should be simpler. SCE proposes no volume or transaction rate limits for short-term transactions, which it defines as electrical energy or gas transactions, including transactions for the transmission or transportation of the commodity, entered into within 31 days of delivery for a term that does not exceed one calendar month. SCE also proposed forward transaction limits and price benchmarks for transactions. SCE states that its choice of products and methods of transactions are consistent with the adopted plan for 2003 and are reasonable.

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."20

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.

7. 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; and

6. OASIS sites

Although we agree with ORA that their recommended 11-step procurement process represents a prudent and common-sense approach, we do not explicitly require the utilities to follow the process. For short-term transactions, the process is clearly too burdensome. For longer-term transactions beyond 90 days, such as long-term Power Purchase Agreements, acquisition of generating resources, or other significant contracting efforts involving competitive solicitations (i.e., Requests for Offers), we would prefer that the utilities follow a process similar to the one suggested by ORA, but will not explicitly require use of the 11-step process precisely. We do require that the utilities consult with their PRGs for transactions greater than 90 days, but leave to the utilities' discretion the exact process for approaching such procurement. During our review of such transaction, we will, however, look favorably on utilities' demonstration that their procurement practices have followed a process substantially similar to that suggested by ORA.

Whereas SCE and SDG&E identified in their proposed short-term plans the brokerages and exchanges those firms propose to rely on, PG&E did not. PG&E should provide such a list in a compliance advice letter filing updating its short-term plan.

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 outlined 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.

Negotiated bilateral contracting is not amenable to the 11-step process, and therefore we do not mandate it for negotiated bilateral contracts. We grant authority for the use of negotiated bilateral contracting in three limited circumstances. 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 provided they include a statement in quarterly compliance filings to 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.

Last, we expand the authorization for 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

F. Cost of Collateral

In their procurement plans filed with the Commission on May 15, 2003, PG&E and SCE stated that their ability to secure reasonably priced financing for short-term procurement was hindered because of (1) SCE's non-investment-grade rating and (2) PG&E's bankruptcy status. Given their current financial condition, each argued that the procurement options available to them may be limited and costly. The Commission now notes that while PG&E is still operating under the terms of its Reorganization Plan, SCE has recently regained an investment-grade rating from S&P, Moody's and Fitch.

SCE asks that the Commission take steps to improve and maintain its creditworthiness and financial viability by recognizing the costs associated with collateral requirements. It indicates that the ERRA proceeding is the appropriate forum for addressing the impact and treatment of collateral costs. The Commission's policy for assessing the utilities' financial capabilities should consider issues which affect capital structure in tandem with those affecting immediate cash needs. This will ensure that these costs are treated in an appropriate and coherent manner. Moreover, we note that there are elements of credit risk related to collateral issues which transcend cash requirements. The cost of capital proceeding addresses issues relating to capital structure and risk. In the forthcoming decision on long-term procurement, the Commission will focus on long-term financial issues, such as debt equivalency, and will at that time decide the appropriate forum for recovery of collateral costs.

PG&E states that its procurement-related credit capacity is presently capped by a dollar limit as per the terms of its Reorganization Plan. Given these limitations, it expects its short-term procurement options may be compromised, particularly as it is still in bankruptcy.

With respect to the administration of the DWR long-term contracts, the Commission authorized the three IOUs to serve as limited agents for DWR for fuel management services. PG&E states in its 2004 procurement plan that:


"DWR is currently arranging [for gas hedging for the DWR contracts] and would continue to do so under PG&E's proposed gas supply plan. However, to the extent that DWR fails to continue to hedge gas prices under its contracts, it is likely PG&E would not have sufficient credit capacity to enter into such hedges given the other demands for its limited credit capacity. PG&E, therefore, requests that the Commission relieve PG&E of any responsibility to hedge gas on behalf of DWR to the extent PG&E's collateral requirements associated with such hedges, in combination with other procurement-related collateral requirements would exceed PG&E's ability to provide such collateral."

First, the Commission reminds the IOUs that the inherent responsibilities in managing and procuring for a integrated DWR/URG portfolio, subject to the requirements of least-cost dispatch, means that portfolio segregation is not possible. Second, we refer PG&E to Article 14.4 of its Servicing Order, that address conditions for force majeure. Specifically, we refer to language which states "Any Insolvency Event shall not constitute force majeure." We do not grant PG&E's request for relief.

The utilities suggest other approaches to dealing with limited credit capacity. PG&E states that the Commission can increase the utility's available credit capacity by increasing the authorized rate of return, by improving various cost recovery mechanisms to limit overall business risk, and by providing for stable decision-making. As a procedural matter, we find that the appropriate forum for issues relating to capital structure is the Cost of Capital proceeding. We refer such issues to that proceeding.

It is essential to balance the cost of collateral against the risk of counterparty default. PG&E currently has a non-investment credit rating, and with it, limited sources from which they can secure collateral financing. One possible solution is to rely more on transacting with similar non-investment grade counterparties, without collateral support. However, as a general rule of thumb, companies seek to limit their credit/counterparty exposure by primarily transacting with creditworthy counterparties and/or by requiring counterparties to post collateral.

The Commission recognizes the dearth of financially stable and viable trading counterparties in the market, as well credit contraction in the industry, and the implications of these conditions on each utility's credit policy. If the Commission does not establish credit standards here and the utilities' counterparties default on their contractual obligations, ratepayers may be harmed.

We now set in place credit guidelines to support 2004 transactions. With respect to unsecured credit limits, when dealing with non-investment counterparties, the Commission insists that as a first option, utilities explore the use of credit mechanisms such as parent company or third party guarantees, letters of credit, surety bonds, etc. The credit assessment should rely on master agreements with special parent and or guarantor provisions for posting collateral and for assuring continuity of service. When dealing with investment-grade counterparties, we approve of the credit thresholds proposed by the utilities. Credit criteria for non-guaranteed government entities are approved, according to the guidelines proposed by each IOU.

G. 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.

8. 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 STPPs on May 15, 2003, each IOU shall update its short-term plan by compliance advice letter within 30 days from the effective date of this decision to reflect more recent fuel price forecasts and resulting changes to the loads/resource capacity and energy balance tables and residual net open estimates. Each utility shall meet this requirement by furnishing updated tables to its short-term plan in its compliance advice letter filing. Resubmission of the entire plan is not required.

H. 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 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 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"21 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."

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 activity.22 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."23 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 the PRG process has been beneficial, and we authorize its continuation through the end of 2004. 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 more often than quarterly under circumstances when portfolio risk exceeds the CRT as described elsewhere in this decision.

Even with an incentive mechanism and upfront standards and criteria in place, the PRG can serve during 2004 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.

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.

I. 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. From the Commission's perspective, there are three disadvantages to SCE modeling this methodology. First, as it has modeled a cost allocation methodology not authorized by the Commission, we are now asked to approve a procurement plan that may include skewed measures of procurement cost and portfolio risk relative to estimates under the Commission-approved pro-rata cost allocation. Second, modeling based on a cost allocation methodology not approved by the Commission undermines the principle of transparency, on which the Commission bases its procurement policy. Third, developing policy that dictates the appropriate "signals" for operating, procurement and management of utility portfolios is within the purview of the Commission and is not a utility-specific determination.

Further, there is no record in this proceeding on methodologies for cost allocation of the DWR contracts, nor have other parties had the opportunity to be heard on this issue. The appropriate forum for revisiting this methodology is the 2004 DWR revenue requirement proceeding. That proceeding has been bifurcated into two phases. In the first phase, the IOUs have been ordered to adopt an interim allocation for the 2004 revenue requirement using the methodology adopted for 2003 in D.02-12-045. In the second phase, a final allocation methodology for 2004 will be litigated on a less expedited schedule. The final allocation methodology will be applied retroactively to January 1, 2004.

The application of the final cost allocation methodology can and will be applied retroactively, due to the fact that it involves a regulatory, non-market process. However, given procurement activity in financial markets, any incremental portfolio risk incurred as a result of modeling based on a non-approved methodology cannot be "trued up." SCE must amend its plan and model its procurement costs and estimate portfolio risk based on the pro-rata allocation approved by the Commission.

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.

We adopt the short-term plans of the respondent utilities as modified herein. The effective date of the short-term plans is today.

Each utility should file by compliance advice letter within 30 days of the effective date of this decision revisions to its short-term plan that conform to this decision. These plans shall conform to all Commission decisions unless specific findings are made here to change a previous Commission decision.

20 SDG&E ST Plan, page 21 21 SCE Brief on Generation Procurement, May 6, 2002, p. 11. 22 Hearing Testimony, Witness Jeung, July 25, p. 4100. 23 Hearing Testimony, Witness Cini, August 7, pp. 5222-24.

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