IV. Threshold Policy Issues

The three threshold policy issues addressed in this decision are (1) adoption of a resource adequacy framework, to include specific reserve level requirements; (2) adoption of a market structure for longer term resource commitments by the utilities and a requirement to include long-term investment in their procurement planning; and (3) an analysis of whether each utility will be financially capable of making the longer term investments necessary to meet its obligation to serve its customers. In discussing these issues, we give specific direction for the utilities to follow in their procurement planning and operations.

A. Reserves and Resource Adequacy

1. Summary

Resource procurement traditionally involves the Commission developing appropriate frameworks so that the entities that it regulates provide reliable service at least cost. This involves, as was done in this proceeding, the determination of an appropriate forecast of demand and then ensuring that the utility either controls, or can reasonably be expected to acquire, the resources necessary to meet that demand, even under stressed conditions such as hot weather ⁶ or unexpected plant outages. "Resource adequacy" seeks to address these same issues. Therefore, in developing our policies to guide resource procurement, the Commission is providing a framework to ensure resource adequacy by laying a foundation for the required infrastructure investment and instruments to assure that capacity is available when and where is needed.

In this decision, the Commission directs that: 1) in order to provide reliable service utilities have an obligation to acquire sufficient reserves for all their customer load; asks the ISO to implement the resource adequacy framework adopted in the decision for all participants in its market; adopts a 17% reserve level with a +/- 2% "deadband"; directs the utilities to meet this 17% reserve requirement by no later than the beginning of 2005; establishes a requirement that utilities forward contract 90% of their capacity needs a year in advance and 100% of their capacity needs a month in advance; and continues the 5% limitation on utilities' reliance on the spot market (i.e., Day-Ahead, Hour-Ahead, and Real-Time energy) to meet their energy needs.

An Assigned Commissioner/ALJ Ruling issued in this proceeding on September 25, 2003,directed the convening of workshops to address the issue of standardizing, to the greatest extent possible, the load forecasts and methodologies used by the utilities to value and count resources. Today's decision also provides further guidance to these workshops on the issue of counting resources, particularly with regards to maximizing the use of the preferred resources (energy efficiency, renewables, demand response) identified in the Energy Action Plan to meet California's energy needs and the DWR contracts. This decision also addresses other miscellaneous issues associated with resource adequacy including deliverability and day-ahead commitment.

B. Policy Issues

While virtually all parties in this proceeding agree that it is critical for California to ensure adequate reserves and address resource adequacy, there are a number of policy issues that must first be resolved.

First, there is a trade-off between reliability and least-cost service given the cost to acquire and retain reserves. As TURN's witness Woodruff noted, each incremental increase in reserves offers progressively smaller improvements in reliability. As SDG&E calculated, each additional 1% increase in reserve level adds $2.8 million to its costs.

Second, there are a broad range of resource applications and technologies that California can rely on to meet its reserve levels. The Energy Action Plan, as well as the guidance given for this proceeding, established a "loading order" for new resource additions emphasizing increased energy efficiency, renewable energy, and demand response/dynamic pricing. The development, timing, and calculation of a reserve level can have a significant effect in promoting development of these new resources. With that said, the Commission recognizes that with regard to capacity reserves (i.e. the ability to "call" on a resources when needed, particularly when the system is at peak) it is critical that a particular capacity resource be both dependable and deliverable when it is required.

Third, there is the issue of reliance on the spot markets to meet a portion of capacity and energy requirements. While no party advocates extensive reliance on the spot market, some parties believe that it may be both reasonable and prudent to allow for some portion of resource needs to be met through the spot market.

Fourth, there is the need to evaluate resource adequacy in the context of the broader regional energy market and the market design rules that these markets will operate under. Both the ISO (in its MD-02 proposal, and FERC (in its SMD proposal) are in the process of redesigning these markets. Any actions taken by the Commission should work seamlessly and in concert with these efforts.

C. Current and Forecasted Market Conditions

The Joint Recommendation states a 15% planning reserve should be in place by 2008. Individual parties' testimony, including the Edison, PG&E, and TURN indicate need in 2008. SDG&E states that it will require new resources as soon as 2005.

The CEC, based on its review of the California energy market believe that new capacity needs are unlikely to occur until 2007, at the earliest. As the CEC also notes, its review (as well as those of the utilities) are based primarily on a review of existing and planned generating resources and do not consider non-generating resource additions (such as increased funding for energy efficiency) that would defer further into the future the need for new resources. The CEC also expresses the concern that focusing on reserve levels based only on generating resources may bias planning decisions to the detriment of demand-side resources such as energy efficiency.

The ISO and CPA by contrast, maintain that capacity constraints could appear earlier than 2007, and that mid to long-term commitments will ensure the maintenance and development of resources to meet demand. IEP and WPTF make somewhat similar points, arguing that ensuring the availability of existing resources should be considered in setting reserve levels.

D. Appropriate Reserve Levels and Phase-in Period

While virtually all parties agree that it is appropriate to set a reserve level, parties disagree over both the level and whether a phase-in period is needed to achieve it. The Joint Recommendation proposes a 15% reserve level, phased in between now and 2008. For 2004, the utilities propose to continue to meet the 7% Operating Reserve level required by the ISO.

It is important to specify definitions at the outset to minimize confusion and provide clarity. In order to ensure reliability, a grid operator must ensure that there are sufficient resources available to meet peak demand, plus an additional reserve to accommodate unexpected outages. The level of the reserve is determined by the Western Electricity Coordinating Council and is approximately 7% of peak demand.⁷ This is the operating reserve.

"Planning reserves" involve a longer-term perspective of ensuring that in real-time there will be sufficient energy to meet peak demand plus needed operating reserves. Typically this requires that a utility have more than 7% reserves, since at any given time some percentage of plants may not be available due to such factors as maintenance, forced outage, fuel limitations, or in the case of hydroelectric power (insufficient water conditions). Planning reserves are typically 15-18%.

A planning reserve represents capacity to ensure that generation is available when required. This capacity or "call" option covers a generation resource's fixed costs. Essentially, this means that a generation resource receives a payment to reserve a specific quantity of power in the event that it is required. This capacity, or "call option", is not the same as energy, which is a commitment to actually provide the power. However, if that capacity is called upon in the day-ahead or real-time markets, the generator can be asked to "burn fuel" and is then an energy resource. It should be noted as well that many long-term contracts contain provisions for both capacity and energy.

The CPA, based upon its study (officially noticed as part of the record) recommends the adoption of a 17% planning reserve level. The ISO supports the 17% reserve level and maintains that utilities should meet a 90% year-ahead/100% month ahead capacity procurement requirement (i.e. peak load plus reserve). Finally, IEP supports the 17% reserve level, while WPTF states that the reserve level should be "at least 15%."

We commend the considerable efforts that the CPA has undertaken in meeting its statutory responsibility to assure adequate reserves to maintain system reliability. Given that reserve levels are a fundamental reliability issue, we have given considerable weight to both the CPA's and the ISO's position that a 17% reserves level is required to ensure reliable operation of the grid and reduce the ability of sellers to exert market power. Therefore, based on the record developed in this proceeding, we make permanent a 17 % reserve level. This reserve level is consistent with historic reserve levels, which have traditionally ranged from 15-18%, and at times have been considerably higher. It is also consistent with reserve levels around the country. We also agree with SDG&E that a +/-2% "deadband" is reasonable given variations in load and the lumpy nature of individual reserve additions. We clarify that the 7% operating reserve that is required by the WECC is included in the 17% reserve level.

With regard to a phase-in period, the utilities should meet this 17% requirement by no later than the beginning of 2005. This approach is consistent with proposals submitted by many parties including the CAISO and SDG&E. Nearly every party in this proceeding concedes that supply in the West is currently low-cost and available. Many parties, such as those supporting the Joint Recommendation, argue that abundant low cost power favors a substantial reliance on the spot market to meet capacity requirements. However, we find these arguments support the contrary approach. That is, utilities should use the availability of low cost power supplies to lock-in prices so that consumers can benefit from the lower prices over the longer-term and ensure that the power is available to California customers. Many parties note the availability of reasonably priced supply in the West, but that supply is not assured to California consumers unless it is assured through contract.

Taking advantage of the current supply situation will not only foster stable, reasonable prices in the mid-to long-term, but it will also provide a foundation for investment in new resources and modernization of existing resources. We further note that it takes time to develop new infrastructure and the Commission would be unwise, and consumers ill served, if the State were to wait until it lacks the resources it needs before providing for their development. Establishing a 17% reserve margin beginning in 2005 will provide for a sensible development of resource that assures sufficient supplies in the long-term and that they are available when they are needed.

In setting these targets we do not believe that we are setting a reserve level that will be difficult for the utilities to achieve. In their original filings, for example, each of the utilities, as WPTF notes, proposed target reserve levels in the 15-17% range to be achieved by the 2005-2006 timeframe.

Additionally, although several parties were opposed to the proposal that each utility only meet the ISO's 7% operating reserve requirement for 2004, a closer look at the utilities' filings shows that their actual reserve margins for 2004 were significantly above the 7% minimum. SDG&E's testimony, for example, shows that it possesses sufficient capacity, either owned or under contract, to easily meet the 7% operating reserve requirement, implying that SDG&E's actual planning reserve levels are well above 7%. A review of Edison'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, Edison'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.

E. Appropriate balance between forward contracting and spot purchases

The ISO was the only party to propose specific percentages that each utility should forward commit to, proposing that utilities forward contract 90% of their capacity needs (i.e. peak load plus reserves) a year in advance; and 100% of their capacity a month in advance. This proposal was opposed by, PG&E, and the Joint Recommenders.

In determining what an appropriate benchmark for forward contracting should be, we should begin our analysis of what the de facto percentage of forward contracting is based upon each utilities' existing portfolio of retained generation and assigned DWR contracts. Summarizing at a high level, to respect confidentiality concerns, it appears that for many months of the year (particularly off-peak or shoulder months) that the utilities are already forward contracted at the 90% level and in some months may actually be net sellers into the market (i.e. greater than 100% coverage.) Even for the peak summer months, the degree of forward contracting appears to be in the 70-75% range, without taking into account subsequent activities undertaken by the utilities since they resumed procurement in January 2003⁸.

The question therefore becomes what are the benefits of further forward contracting. As noted when the DWR contracts were originally signed, it was thought that being forward contracted at somewhere around the level of 70-80% was sufficient to minimize the incentives for generators to engage in physical or economic withholding.⁹ Forward contracting also provides price stability, a revenue stream for investment in new resources and maintenance of existing infrastructure, as well as increased grid reliability.

Also important, as PG&E notes, imposition of a mandatory percentage of forward contracting is inconsistent with the risk assessment models the utilities are supposed to develop and use to minimize ratepayer risk exposure.¹⁰ The purpose of these models, as PG&E notes, is to minimize price and risk volatility. Thus, these models should inherently result in utilities seeking to forward contract to a significant extent, to optimally minimize exposure to any high prices or reduced reliability of spot market purchases. Optimally designed, these risk assessment models would more precisely match and determine the optimal forward contracting strategy than setting an arbitrary percentage as the ISO proposes.

However, given a relatively low difference between the current de facto level of forward contracting and the 90% level, we propose to adopt the 90% annual capacity reserve level. That is, the utilities should procure 90% of their capacity requirement a year ahead to reflect their monthly forecasted peak requirements (i.e. a utility will procure 90% of a particular month's forecasted peak a year ahead). We note that we are directing a 90% capacity reserve level, and that utilities have full flexibility to contract for energy until real-time, consistent with the 5% limitations on spot energy purchases described below, in order to assure least-cost procurement for consumers. The flexibility to use short-term markets for energy purchases should address PG&E's concern regarding its ability to comply with the risk assessment models and assure least-cost dispatch objectives.

Assuring capacity reserves at this level will provide a safeguard against the exercise of market power, provide a foundation for investment in new and existing resources as well as provide stability to the markets. Because the difference between the existing level of forward contracting (70-100%) and the proposed target, utility compliance with this level appears feasible. As PG&E, notes, however, establishing this requirement for 2004 would require that PG&E complete, and receive Commission approval for its procurement strategies, for acquiring its necessary 2004 reserves by this month, November 2003. Therefore it is appropriate to defer implementation of this requirement to the beginning of 2005.

The ISO proposes that utilities' forward contract for 100% of their capacity needs a month ahead, a position opposed by other parties. That is, the ISO proposes that utilities forward contract 90% of their required capacity a year in advance and then "firm up" 100% of their forecasted peak load plus reserves no later than a month ahead. The ISO argues that to maintain reliable grid operations by ensuring that sufficient reserves exist, it must know ahead of time the resources that are available. Absent this resource information, the ISO will be forced to rely on other means, such as the must-offer obligation and the residual unit commitment (RUC) process, to ensure that adequate supply is available to meet demand in real-time. The ISO also argues that ensuring that 100% of forecasted capacity needs are met a month ahead will serve to reduce the risks of high prices in the short-term markets and decrease the need to rely on the RUC process, which is costly for consumers.

The Joint Recommendation maintains that utilities can rely upon the spot market for some percentage of their needs while still ensuring reliable service. SDG&E argues that the 5% limitation on use of the spot market, that the Commission established in D.02-10-062, be eliminated. In large part, the sensibility of relying in the spot market depends upon the shape of the underlying market and expected availability. In order to ensure reliability, however, a concern of many parties, including the ISO, is that any reliance on the spot market be based on reasonable (and perhaps even conservative) estimates of the energy available in this market. As the CEC notes, we do not want all three utilities assuming they will be able to acquire the same spot energy from the Pacific Northwest.

In D. 02-10-062 the Commission adopted a limitation on spot purchases to less than 5%, consistent with least-cost dispatch objectives. That is, the utilities should attempt to confine day-ahead and real-time energy purchases to 5% of their needs, but utilities can engage in higher levels of spot transactions if they are justified for least-cost dispatch. This limit was to provide a balance between flexibility and reliability. Such guidance for procurement practices is valuable and should be continued in the utilities' current procurement practices. That is, while we maintain that 100% of reserve capacity should be "locked-in" a month ahead we give the utilities the flexibility to shop around for the lowest prices with regard to their energy needs, subject to the 5% limitation. That means the utilities have flexibility with regard to 95% of their energy requirements. We maintain the 5% limitation on spot energy purchases in a belief that over-reliance on spot markets is unwise.

Establishing a firm target of meeting 90% of capacity needs a year ahead and 100% firming up of capacity a month ahead while limiting energy spot purchases to 5% will serve to assure that sufficient capacity will be available if they are required while allowing the utilities ample flexibility to procure their energy needs. In other words, the Commission does not believe that short-term markets should be relied upon for capacity needs, but that short-term markets can be valuable in meeting energy requirement in a least-cost manner. We note in addition that assuring 90% of capacity requirements a year ahead and 100% a month ahead will not only support investment in new and existing resources in the long-term, but provide for sufficient reserves in the short-term while simultaneously serving system reliability, a measure to reduce the ability to exercise market power, and provide stable prices.

We also note that contracting for the ability to "call" on resources if they are required assures that they are available to the California market. While there may be adequate resources in the West, they are not assured to California unless the capacity is contracted for. In addition, assuring that these resources are available to California may result in downward pressure on energy prices in the short-term markets.

Furthermore, reliance on short-term markets for capacity leaves consumers vulnerable to potentially high prices and market power abuses. In other words, over-reliance on short-term markets for capacity increases the level of dependence on FERC's determination regarding price mitigation and the must-offer requirement.

We maintain that the must-offer obligation has served a critical function in the California market. It prohibits physical withholding of energy, and is a fair condition of a sellers' market based rate authority. The must-offer requirement was not intended to be used to provide capacity, and should not be used as a tool to assure adequate capacity. There are two key reasons for this. The first is that the must-offer requirement does nothing to foster investment in existing or new resources. The second reason is that continuation of the must-offer is uncertain and subject to a determination by FERC. As ORA notes, the must-offer obligation cannot assure that new resources will be built or that existing plants continue to operate. Indeed, the reality is that the current framework is not providing an adequate foundation for investment in new or existing resources as evidenced in the recent mothballing of Duke and Reliant generating facilities and the retirement of Mirant and Reliant generating units.

In short, an approach that depends on short-term markets to meet capacity requirements increases dependence on the must-offer requirement to assure that resources are available when needed while simultaneously undermining the likelihood that investment in new and existing resources are adequate in the long-term. Therefore, we affirm our position that a portfolio approach emphasizing mid-to long-term contracts is a preferable approach to meeting capacity requirements. Contracted capacity assures stable prices and that supply is available in California when it is needed.

We maintain further that mid- to long-term contracts, as a vehicle for providing revenue adequacy, are critical in fostering the development of new resources and maintenance of existing ones. The Commission continues to support the Residual Unit Commitment process, which the ISO has outlined as part of MD02, as an essential tool for maintaining reliability in the following day's market. However, we are concerned that the capacity payment that generators would receive in the Residual Unit Commitment process that FERC has recently approved could provide the opportunity for a "double-payment". As Edison notes in its rebuttal testimony, resources that are used to satisfy the utilities' resource adequacy requirement should be made available to the ISO in the real-time market to maintain reliability. The ISO's RUC process is essentially a process that allows the ISO to line up resources day-ahead if they are needed to meet any projected shortfalls the following day. FERC, in its Order dated October 28, 2003¹¹, supported a capacity payment to generators in the RUC process, regardless of whether the unit is dispatched, as FERC views the RUC process as a call option on the supplier's capacity. The FERC also set the RUC bid-cap at $250/MWh rather than the $100/MWh supported by the ISO and the Commission and allows these units to set the market-clearing price.

The RUC capacity payment was originally meant to be a transitional mechanism to fill the gap until such time as a resource adequacy policy was in place, whereby generators would be paid for capacity and thus receive fixed cost recovery and a sufficient incentive to invest in generation. The FERC does not indicate in its October 28^th Order that the RUC capacity payment is interim in nature. Our concern is therefore that generating resources will receive the RUC capacity payment in addition to being compensated for meeting the LSE's resource adequacy requirement. The Commission cannot support such a double payment. The Commission agrees with Edison's point that once the LSE's have paid for a capacity resource and met their resource adequacy requirement through long-term contracts, that the ISO should have "automatic" access to that capacity to maintain reliability. These resources that the LSEs have already paid for and made available to the ISO should not receive additional capacity payments in the RUC process. As part of the ISO's MD02 proposal, the RUC process would not go into effect sooner than early 2005. In contrast, the utilities resource requirement as outlined in this decision will be effective immediately and will be met by the beginning of 2005, at the latest.

The Commission supports RUC as a necessary tool in enabling the ISO to maintain system reliability. Therefore, the Commission intends to work with the FERC, the ISO, and the utilities to ensure that the RUC process functions in concert with the resource adequacy provisions directed by this decision to ensure that consumers are not double paying for capacity.

F. Utility Obligation to Procure for all load and customers within their service territory

While almost all parties stated that ensuring adequate reserves was an important issue, parties disagreed over the appropriate methods to achieve this goal.

The Joint Recommendation proposes that reserves be acquired for all load within each utility's service territory, but does not address who or how these reserves will be procured. Several parties believed that either the FERC or the California ISO should have this responsibility.

The Commission has maintained in a variety of forums that it should set the framework in determining resource adequacy and procurement issues. The FERC also supports a state determination on resource adequacy. FERC, in its recently released "White Paper" on Standard Market Design (SMD) states that it would:

"Allow an RTO/ISO to "implement a resource adequacy program only where a state (or states) asks it to do so, or where a state does not act."..."States may decide to ensure resource adequacy through state imposed requirements on utilities serving load within the region...¹²"

FERC, in its recent October 28^th Order addressing the redesign of the California wholesale electric market reiterated this conclusion noting that it was "encouraged that the State has undertaken a procurement proceeding, (Order, para. 215) and would defer consideration of many elements of the ISO's proposal until 60 days after the final rule issued by the CPUC within this proceeding. (para. 216.)

Several parties agree that the state is an appropriate entity to address reserve issues. (TURN, California ISO). SDG&E and Edison contend that the Commission could impose reserve requirements upon non-utility LSEs (such as Energy Service Providers) under the requirements of PU Code 394. This code section allows the Commission to determine that ESPs demonstrate "technical and operational reliability" and "financial viability." As Sempra states, "apart from the law and theory, the State as a matter of public policy may determine that system reliability requires that LSEs meet a resource adequacy test, inclusive of supply reserves." PG&E maintains that all LSE's must self-provide or pay the cost of acquiring their share of planning reserves. It argues that because LSE's are interconnected, adopting reserve levels only for IOUs will not guarantee service reliability if other entities such as direct access or community aggregators are exempt from the requirement.

ARM and WPTF dispute the Commission's authority to use the "reliability" requirements of PU Code 394 to impose reserve requirements upon all LSEs.

The Commission affirms in this decision its intent to establish a resource adequacy framework for the investor owned utilities that it believes should be consistent throughout the State. We agree with PG&E that given the interconnected nature of the Western grid, it is critical that resource adequacy be applicable to all LSEs. Indeed, as the Energy Crisis has proven, resource adequacy is a regional issue given that the lack of sufficient resources in one area of the West affects the entire region. While the Commission has established a framework for resource adequacy for the investor owned utilities in this decision, we believe that the ISO is best positioned to implement these requirements. The ISO is in a position to require that all LSE's that participate in its markets meet the resource adequacy requirement outlined in this decision. That is, the ISO should make the requirements that are outlined here for the IOUs, applicable to all LSE's in the ISO markets. The ISO has testified that it is willing an able to carry out the implementation of resource adequacy provisions determined by the Commission. This approach will ensure a higher level of grid reliability both regionally and within California, consistency throughout the State, and create a platform for coordination on a region-wide basis. Furthermore, this approach will mitigate any issue associated with "free-riding" since having the ISO implement these provision for all market participants will assure resource adequacy to the largest degree possible across the State. The Commission contends that a fragmented and inconsistent resources adequacy standard across California will only undermine region-wide reliability objectives.

G. Deliverability

In general, the utilities in their filings sought to address the issue of ensuring that generating resources upon which the utilities plan to rely were deliverable to load. As Edison notes, the models upon which it relies take into account general transmission constraints in order to ensure that proposed resource additions can be delivered to the load. Such an approach is reasonable for longer-term planning purposes in identifying and evaluating various resource options to meet demand. It is also critical in linking generation and transmission in a way that can facilitate least cost investments. As the utilities' resource choices become more focused (for example selecting a specific plant or transmission path to access a resource), the utilities should demonstrate that such resources are deliverable to load under adverse system conditions. Indeed, the threshold issue with regard to capacity resources is that they are available when the system is stressed at peak and needed most.

SDG&E (based in large part upon work done by the ISO) offers a more specific example of how resources should be evaluated for deliverability once they become more clearly identified, stating that:

"In regard to deliverability of potential resource additions internal to the SDG&E LRA that are currently in SDG&E's or the ISO's interconnection queues, we have completed (or are in the process of completing) generation interconnection studies that have been (or will be) reviewed by the ISO pursuant to their established tariff procedures. Furthermore, prior to contractually committing to a capacity purchase from any project in our generation study queue that seeks to meet SDG&E reliability needs, we would complete further deliverability analysis for review by the ISO. For other generic resource additions internal to SDG&E's service area that are not presently in the interconnection queue, we have not identified any specific transmission deliverability upgrades in our opening testimony. However, SDG&E intends to develop a transmission plan of service for such resources that will satisfy deliverability requirements. These studies will also be submitted to the ISO for their review.

Furthermore, it is critical that deliverability of a resource located outside an LRA be determined for both normal and emergency conditions. This is necessary because remote resources that can be scheduled for delivery to an LRA under normal operating conditions may not be deliverable during certain transmission contingencies when they are needed to serve the LRA's reliability needs and vice-versa".

Such a definition is a useful starting point to address deliverability requirements for capacity resources. Deliverability is an essential criteria for IOU capacity contracts. Given the ISO's expertise with respect to the transmission system, we request that the ISO propose a definition of resource deliverability for use in contracts that will count towards IOU resource adequacy in the workshops that are scheduled for December 10, 2003. We invited parties to comment on the ISO's deliverability definition.

We are aware of FERC's most recent pricing policy requiring transmission owners to provide a credit to generators for network upgrade¹³ costs, which are ultimately paid for my ratepayers. However, we note that in the Eastern ISOs with capacity markets, generators must pay for deliverability upgrades to qualify as an eligible capacity resource. Generators are then compensated for the transmission investment with property rights, such as congestion revenue rights¹⁴.

The Eastern ISO model-with our determination on resource adequacy matters substituted for an ISO-run capacity market-appears to be compatible with the direction the ISO is taking in MD02 with respect to Locational Marginal Pricing and Congestion Revenue Rights, since generators that pay for deliverability upgrades could be compensated with CRRs.

Such a model appears to provide more rational incentives to generators that are currently insulated from transmission related costs under the FERC's crediting mechanism. We also believe that from a cost allocation perspective, a more equitable and efficient outcome for consumers is one in which generators pay for network upgrades to ensure power deliverability. We believe that defining deliverability and making it a requirement for qualification to meet a LSE's resource adequacy requirement it an important step towards harmonizing and synchronizing generation and transmission planning and remedying existing perverse incentives that exist with regard to generation siting.

H. Penalties and Reporting

Several parties propose that the Commission establish penalties that would result as a consequence of not meeting the resource adequacy obligations set out in this decision. The ISO believes that utilities and other LSE's that fail to procure sufficient resources on a month-ahead basis be subject to financial penalties or, alternatively, be designated for first curtailment in the event of a resource deficiency. The ISO notes that depending on the outcome of this proceeding it may propose tariff changes that would institute a surcharge for real-time energy purchases during a Stage 1, 2,or 3 energy that was purchased by an LSE that did not obtain sufficient resources. Alternatively, the ISO may propose a curtailment priority list to be used in real-time. ORA seems to agree with upfront procedures to address non-compliance with the resource adequacy provisions. ORA notes that it is too late and too expensive to wait until there are inadequate resources before addressing this issue. TR. (Mobosheri) at 5110: 23-28; 5111: 1-3.

The Commission agrees that reasonable consequences should exist for a LSE's failure to procure sufficient reserves. We support the ISO's proposal that a LSE that has not procured sufficient reserves pay a surcharge on real-time energy in the event of a staged emergency. We do, however, clarify that we think this penalty surcharge should be limited to the event of a staged emergency and that the ISO should notify the Commission with regard to routine lack of compliance regarding the resource adequacy requirement set forth in this decision. We would like to work with the ISO in establishing the surcharge. Therefore, we will ask that the ISO propose a surcharge that would be applicable during staged emergencies in the December 10^th workshop to allow for sufficient comment and input.

The ISO proposes a reporting requirement to assure that the utilities comply with their obligation to be resource adequate. The CEC seems to support reporting requirements as well. PG&E states its willingness to work with the CAISO, the CEC, and others proposing reporting requirements, but notes that the utilities are already required to submit to the Commission annual procurement plans as well as monthly forecasts of the net open position on a rolling 12-month basis. PG&E suggests that the CPUC, CEC, and CAISO coordinate reporting requirements to avoid duplicative effort. Edison does not object to the concept that the utilities' resource adequacy reviews consider whether the resource portfolio that the utilities propose to meet annual requirements also meet monthly requirements. However, Edison maintains that such a review should be part of the annual review and not a monthly reporting requirement to the ISO.

We agree with the ISO that LSEs should demonstrate on a monthly basis that they have procured sufficient capacity to meet their needs. In order to be able to assure grid reliability and minimize costly and inefficient mechanisms to assure adequate capacity, it is reasonable that the ISO knows what resources will be available and that the LSE's have met their capacity requirements. However, we are sensitive to PG&E's point that the utilities should not be overly burdened with reporting requirements and that opportunities to avoid duplication should be taken. Therefore, we direct the utilities to propose a process for a monthly reserve demonstration, to both the ISO and the Commission, that is least burdensome and most consistent with current reporting requirements.

I. Issues to be Addressed in Workshops

A previous Assigned Commissioner/ALJ Ruling in this proceeding directed the convening of workshops to address the issue of standardizing, to the greatest extent possible, the load forecasts and methodologies used by the utilities to value and count resources. This workshop is currently scheduled for December 10^th, with a workshop report due back to the Commission by January 15^th.

In conducting the workshop and developing a resource adequacy framework, the Commission reiterates its commitment that full value be given, to the extent that they are consistent with the deliverability criteria set forth herein, to the preferred resources identified in the Energy Action Plan and the long-term DWR contracts. As PG&E and SDG&E both noted in their preferred plans, for example, they are planning to meet a significant portion of their peak demand through the use of energy efficiency programs. As PG&E notes, in order for it to successfully implement these programs, it needs certainty that this type of soft resource is able to count toward meeting any reserve requirements. Otherwise, as PG&E notes, it is essentially paying twice for reserves, thus undermining much of the benefits of pursuing these energy efficiency measures in the first place. The CEC, in its comments, notes similar concerns, namely that these soft resources, if properly assessed, can act to meet energy needs and reduce needed reserve levels. As the CEC notes, both it, along with PG&E, are committing significant resources to the measurement and evaluation (M&E) aspects of these programs in order to ensure that targeted energy reductions can be verified as actually occurring.

The Joint Parties interested in Distributed Generation raise similar concerns with the treatment of distributed generation resources, and the concern is equally valid for dynamic pricing and demand response programs. For example, SDG&E notes that it is reasonable to include conservative estimates of forecasted demand response programs in preparing its resource plan.

In guiding the workshops, we reiterate our concern that these non-traditional resources be fully and fairly evaluated, and that any resource adequacy framework not unintentionally limit the procurement of these resources or bias resource procurement solely toward generation-only resources.

Consistent with the direction provided herein, the utilities should propose a process for demonstrating on a monthly basis, to the ISO and the Commission, that they have meet their resource adequacy obligation.

We also ask that the ISO specify the surcharge penalty that it suggests should be applicable to real-time purchases that are made by reserve deficient LSEs during a staged emergency. As described in the deliverability section, the ISO should also propose a deliverability definition for comment by parties and adoption by the Commission.

Additionally, a concern of the Commission is that consumers receive credit and value for the long-term contracts entered into by the DWR, to the extent that these resources are dependable and deliverable. That is, to the extent that the DWR contracts are deliverable and dependable, they should count fully toward the utilities' resource adequacy requirement.

J. Market Structure for Longer Term Resource Commitments

1. Determining the Need for Resource Commitments

At the March 7, 2003 PHC, clear direction was given to the utilities to consider all cost effective energy efficiency, demand response, and renewable resources prior to considering the addition of conventional supply or transmission resources in meeting future resource needs. In addition, utilities were directed to include provision for customer-owned, as well as utility-owned, distributed generation, and to propose a methodology for weighing the tradeoffs between transmission and generation investments. This prioritization of resource additions is consistent with our direction in D.02-10-062 and the loading order of resources stated in the Energy Action Plan.

Our record here supports further policy direction on resource selection. To the extent that new generation resources are required, the utilities should first consider the overall advantages of repowering at existing plants or of development of brown field sites located close to load rather than development of new green field sites remote from load and requiring substantial transmission and other upgrades to the system. We prefer that generation assets be sited in California and that they minimize the overall economic and environmental impact, including the costs of transmission and power losses.

Next, utilities should increase the degree of diversity of fuel types and sources for the generators serving California electric customers. To the extent it is cost-effective, utilities should be looking to new generation capacity that is not powered by natural gas, currently the prime mover for 42 percent of the electric energy consumed in this state.¹⁵ Options for fuel diversity include: (1) other fossil fuels, i.e., coal or oil, which carry emissions costs risks; (2) Energy Efficiency and Demand Response programs; ( 3) renewables; and (4) transmission.

The hearing record shows a need for the utilities to commit to new or refurbished generation capacity in the next few years and also provides a fuller discussion in several areas on how that should be done. Therefore, we need to adopt specific rules for how the utilities should acquire long-term resource additions.

2. Today's Hybrid Market Structure

California's policy regarding utility ownership and control of power plants has undergone profound changes over the years. Prior to the 1980s, the utilities were entirely in control of their own supplies. With the passage of the Public Utilities Regulatory Policies Act (PURPA) in 1978, California, along with the other states, began to welcome cogeneration in the form of Qualifying Facilities (QFs). California began considering proposals to move to a competitive market structure in the 1990s. Under the restructuring process adopted by the legislature in AB 1890, the utilities divested most of their generating plants with the exception of nuclear, hydro, and some remaining fossil capacity. During our state's energy crisis of 2000-2001, new legislation forbade any further divestiture.

Today, at the wholesale level, California's IOUs are primarily relying on short-term energy and capacity products (i.e., less than one-year in term) to meet a substantial portion of their residual net short open positions. A utility's residual net short open position is the result of the utilities' retail load requirement less utility retained generation (URG) resources, existing utility contracts, QF power, and long-term DWR contracts operated under a least-cost dispatch framework. More recently, we are seeing shift towards procurement of longer term contracts (i.e., SCE's Mountainview application and SDG&E's Motion for approval to enter into new resource contracts). There are about 18,000 megawatts (MW) of divested generation in California as well as several newer merchant power plants operating in the WECC region. Jurisdiction over transmission rates and terms of service passed to federal jurisdiction under California's AB 1890 restructuring and is now administered by the California ISO under FERC.

The Commission regulates rates and service for utility retained generation plant and all distribution services, oversees utility procurement practices, oversees Public Goods Charge (PGC) funded energy efficiency and renewable resource programs, and establishes rules for direct access. At the retail level, about 13% of IOU aggregated load is direct access, meaning it is served by competitive energy providers; the ability of new customers to sign up for direct access is precluded by legislation. The utilities are the provider of last resort for all customers within their service territories.

3. Benefits of Utility Ownership v. Benefits of Third-party Contracts

The issue of whether the utilities should own additional generation capacity has been renewed with the resumption of utility procurement. AB 57 takes a neutral position on this issue. In D.02-10-062, we asked the utilities to put forward long-term resource procurement plans that included supply options, and stated that in these plans the utilities should consider both utility owned/retained and merchant generation sources.

In their long-term plan filings on April 15, 2003, no utility proposed owning a new generating plant and only PG&E provided a cost-recovery mechanism proposal for utility ownership of new plant. PG&E proposes the Commission adopt a traditional cost of service ratemaking methodology for utility constructed and owned generation. SCE and SDG&E propose that the utilities consider a mix of generation resources by fuel type and ownership and that the Commission consider the merits of specific projects and cost recovery mechanisms on an individual basis.

Since the long-term plans were filed, SCE and SDG&E have made proposals to purchase and own new generation resources. On July 21, 2003, SCE filed an application for approval of the Mountain View project, a power plant of 1,000 MW capacity that SCE would control through a wholly-owned subsidiary. That project is being evaluated in Application (A.) 03-07-032. On October 7, 2003, SDG&E filed a motion in the instant proceeding that would, if granted, result in ownership of the Palomar project, a 500 MW generation plant to be constructed for its eventual ownership and control. SDG&E's motion also includes a proposed purchase power agreement (PPA) for the output of the to-be-constructed 500 MW Otay Mesa project and several other smaller PPA contracts.

The CEC's reports show that approximately 5000 MWs of new generation have been permitted in California but not yet built. Many market generators that hold these permits are in severe financial distress and cannot continue construction without long-term supply contracts with the utilities or other load serving entities. There is an opportunity today to acquire additional generation cheaply and, therefore, we should not delay in setting out clear market structure rules.

SDG&E observes that there is increasing interest and discussion of the possibility of a future utility role in ownership of generation, as at least a partial alternative to reliance on purchased power contracts with suppliers and exclusively nonutility ownership of future generation. It states that consideration of this would require clear-cut rules that would support a long-term utility role in serving a stable customer base.

Benefits of utility ownership cited by SDG&E include the stability and permanence of a regulated utility, the ability of the Commission to directly regulate the price, terms and quality of the generation service provided by the utility, the availability of a proven high-quality workforce (both management and labor) to operate and maintain utility generation, and the increased likelihood that such generation would be located within the State of California.

TURN, IEP, and WPTF recommend that the utilities acquire power through an open competitive solicitation process based on formal request for proposals for PPAs with third-party market generators. These parties express concern about the potential for conflicts of interest by the utility, both in the design of the bid solicitation and the evaluation/selection process, and do not recommend that the utilities be able to compete in these solicitations, or if they do, that there be independent administration of the bid preparation and review process. IEP and WPTF also question whether there can be a level playing field if the utilities are allowed to later request cost recovery of any construction overruns under a cost of service ratebase approach.

TURN proposes that while the utility should not be allowed to compete in the competitive solicitation, it should be prepared to build the plant itself if market bids do not provide the lowest cost means. TURN recognizes that the competitive market does not always work as it "should" and the utilities should pursue a "self-help" alternative for meeting their needs as an insurance policy against potential future dysfunctions in long-term markets.

The primary advantage of third-party bids, TURN, IEP, and WPTF state, is that it provides a market standard for the true competitive cost of new generating capacity. This standard is useful primarily in getting the best deal for ratepayers. It is also valuable in providing a proper benchmark against the cost of alternatives to new capacity, such as demand reduction programs and transmission system efficiency enhancements. In addition, it provides a standard against which the costs of existing and future utility-owned generation could be measured.

Third-party developers assert they exist in a competitive environment that is different from the regulated environment of the utilities. They are subject to market discipline and shareholder control to a greater degree than regulated electric utilities. Their mistakes, cost overruns, and the financial consequences of development of resources that are ultimately not feasible or cost-effective are their own. Third-party power plant developers have no incentive to overcapitalize or to build excess capacity. IEP and WPTF state that utilities will have an incentive to overreach because there is a greater probability that their costs can be recovered.

Further, testimony in support of a competitive market indicates that in the case of a PPA contract with a third-party, there can be clear responsibilities and performance obligations and assignment of costs. The holder of a third-party power contract assumes a great deal of risk. Difficulties that arise during the construction of the plant and later, in its operation, can be resolved in a clear manner, and to the extent that ratepayers are to be charged for additional costs, there will be clarity in how they arose and the resolution of the conflict with the third-party generator. A further point made in testimony is that with the utility contracting with itself there is less clarity about where the risk is held, and costs may be shared or shifted onto the utility's customers.

Several parties assert that by eliminating the utility itself from the competition for new capacity, the number of competitors is reduced, and hence, the degree of competition is reduced. Additional competitors yield greater competition and, as a result, a better outcome for all. However, IEP added that the degree of competition is reduced not only by a reduction in the number of competitors but also by whether the utility itself is a competitor in the bid process. Competition for new generation capacity may be enhanced, not diminished with the utility removed from the competitive process. Allowing the utility to compete to serve itself may result in a bias toward self-dealing or an advantage for the utility's own offerings over those of third-party competitors.

In weighing the arguments on market structure, we find that California should not rely solely on competitive market theory and the behavior of market generators. While market redesign is underway by the ISO and FERC, it is not complete. California has a long history of reliable service being provided by utility-owned and operated generation plant and a recent painful history of rolling blackouts and high price spikes from reliance on third-party generators in a poorly designed competitive market. We agree with SDG&E that a portfolio mix of short-term transactions, new utility-owned plant, and long-term PPAs is optimal, combining the security of generation assets under the full regulatory oversight of the Commission with the flexibility of ten-year contracts, and the potential benefits of operating efficiencies and lower costs from a competitive market. We reference a ten-year PPA based on ORA's recommendation and SDG&E's pending RFP.

We find that designing rules for a hybrid market structure is a complex undertaking. First, a competitive solicitation should be used in order to capture the lowest prices and maximum choices. IEP raises the issue of a level playing field, with the utilities not being able to bid low and then later seek additional cost recovery. The record here shows that the utilities are not well suited to actually construct new plant as it has been twenty to thirty years since they built fossil-fuel plants. Therefore, we expect the solicitations to request turn-key plants and PPAs with later purchase options rather than initial utility construction. If situations arise where competitive bids do not produce adequate response, the utility may need to take on construction, but firm cost caps would need to be in place.

The presumption that utilities may favor their own capacity at the expense of third-party generators is well founded, with effects in both procurement of power from existing resources and in the procurement of new capacity. In their procurement from existing resources, utilities are monitored for their patterns of dispatch to assure that the operations are undertaken in a least-cost manner (i.e., Standard of Conduct No. 4). The presumption is that without that standard, utilities would favor their own resources at the expense of lower cost available alternatives. The historical relationship of the utilities with QF producers similarly leads to concern that given the choice utilities would rather rely on their own resources than on those that come from the market.

The utilities' unwelcoming reception of the California Power Authority's peaker generating units initiative presents a current example of the utilities' desire to avoid contracting with third parties for capacity. The difficulty in adding to California's generating capacity at all during the years of the Biennial Review Proceeding Update (BRPU) process provides a historical example. IEP asserts that the Mountain View procurement application is an example of SCE being unwilling to participate in a competitive process at all. Whether these operating and capital accumulation biases are real or they are only perceived, the Commission should address them.

Careful design and monitoring of a competitive solicitation process and use of a least-cost dispatch standard are important means of addressing the potential for bias. Another means is to adopt a procurement incentive mechanism, so that the interests of utility investors, management, and ratepayers are better aligned. The utilities have an opportunity to invest and earn a return from generation assets; a similar opportunity for profit should be provided for selecting and managing well all other procurement products. We address this in a later section of this decision.

The utilities also request that the Commission provide assurance that our cost-recovery mechanisms will be reliable and consistent over the long term and that we do not adopt policies that would lead to a less stable customer base wherein investments in generation and long-term power contracting would create significant stranded cost exposure. While some of these issues, such as pending legislation to establish a core-noncore market and to change direct access eligibility, are beyond our ability to address here, we are committed to returning the utilities to financial health and to not adopting any mechanisms that would lead to a deterioration of their creditworthiness.

At same time we provide an opportunity for the utilities to own new generation, we want to provide assurance to the third-party generators that we see a meaningful role for them in California's energy future. Third-party generating capacity, if contracted properly, holds a number of advantages for California ratepayers. Moreover, it is necessary to have a thriving independent generating sector for these advantages to be secured. We recognize the financial duress, manifested in significant debt and credit problems, that has beset the merchant generator community post energy crisis. Some firms have closed shop, others have scaled back their operations. We wish to support depth and liquidity in energy markets and, by not letting them compete, this will shrink the market. If third-party generators come to believe, as a result of Commission decisions or utility actions, that an unfavorable market for their services exists in California, then they may withdraw from our state and concentrate their limited resources elsewhere. We would soon face a shortage of serious independent generators able and willing to bid, construct, and operate productive generating capacity here. California would be left with utility development of new capacity as its only option.

4. Competitive Solicitations

Based on our discussion above, the utilities should rely on the formal RFP process to secure future long-term generating capacity resources. The RFP process, if properly designed, calls forth from the marketplace the widest set of choices for development. It is likely to produce the most competitive prices as well, with the possible exception of fleeting-opportunity possibilities.

WPTF argues for a specific structure for capacity procurement that puts procurement via contract on an equal footing with utility-build options. WPTF's proposal is that prior to its issuance, an RFP must be approved by the Commission or an independent third party to verify that it is not tilted in favor of the utility or its affiliate's bid. Second, bids should be evaluated by an independent third party, such as an accounting firm, consultant, or specially convened review panel. Finally, the third party will select a winning bid which, if it meets the criteria presented in the RFP, the utility must accept.

WPTF's proposal would result in a cumbersome process, and one that would be difficult for any utility to endorse, especially as it reserves final choice of contracting partner to a party other than the utility itself. But its need derives from the perception that without the involvement of independent parties in the development of the RFP, the evaluation of the bids, and the ultimate selection of the winning bidder, the utility would have an incentive to act in ways that would bias the process in favor of itself.

The Commission currently has in place safeguards to address WPTF's concerns. First, each utility has a Procurement Review Group (PRG) that consults with the utility in the design of the RFP and the evaluation of bids. ORA proposes an 11-step process for this that we address in a later section of this opinion. Next, the Commission will review all long-term commitments that result from an RFP through its formal process which allows notice to all parties and an opportunity for public review and comment. Based on our continuing review of the RFP process, we will adopt additional safeguards if we find it is necessary.

5. Length and Type of Contracts

As ORA's testimony discusses, over reliance on shorter-term energy markets can be dangerous, as in the energy crisis, and also does not ensure reasonable cost and rate stability due to potential resource shortages and increased prices with price spikes. While commitments beyond one to five years are needed, this does not mean that thirty-year commitments are necessary; ORA testifies that ten-year contracts could provide sufficient assurance for market generators to construct new power plants and five-year contracts could provide generator owners the financial guarantees to invest in emission control equipment and for refurbishing units with the latest technologies. We agree with ORA and SDG&E that a mix of contract lengths, sufficient to allow for new construction of power plants or transmission projects, is best. We also agree with SDG&E that in evaluating an optimum portfolio mix, consideration needs to be given to existing resources and their terms.

Parties discussed types of contracts that could provide the utility increased control and supply reliability. First, with respect to non-unit contingent contracts (i.e., contracts with unspecified resources) with existing resources, ORA proposes that's such contracts should be authorized only for less than one-year in term and executed no more than one-year forward. For contracts for existing resources where the utility would have dispatch rights to specified resources, ORA recommends contract language stating that only specific plants could provide the power, and perhaps ancillary services, with no allowance for substitution from the market. We adopt these contract guidelines. California sited plants, under the must-offer requirements of the ISO and the operation and maintenance standards of SBx2-39, provide additional protection against market power abuses. TURN discussed having contractual arrangements such as step-in-rights and take-over type rights to address longer term issues of supplier nonperformance.

In D.03-06-067 we eliminated Standards of Conduct 6 & 7. We will not reinstate Standards of Conduct 6 and 7, but instead rely on more specific contract terms, as discussed above. We will be able to make a better assessment of the potential for future market power abuses when the ISO and FERC complete their redesign of the wholesale energy market.

6. Affiliate Transactions

a) Existing Moratorium and Standard of Behavior 1

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.¹⁶ (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 on D.02-10-062 and D.02-12-074, PG&E and Sempra raise legal challenges to the moratorium on affiliate transactions and SDG&E and Sempra raise legal challenges to 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."

b) This Year's Hearing Record

In this year's hearings, the moratorium on affiliate transactions was combined with the issue of utility ownership of new generation for the purpose of testimony and briefs. At hearing, the ALJ also asked witnesses whether there should be different rules for short-term and long-term transactions. Additional questions were asked by the ALJ regarding PG&E's and SDG&E's dealings with other departments within their company and with affiliates.

Of the three IOUs, PG&E and SCE focus their comments on utility ownership and do not directly address the moratorium on affiliate transactions, while SDG&E takes a position on both, the stronger position being that the moratorium on affiliate transactions is unnecessary because current rules are adequate to govern any transaction. Further, SDG&E states that transactions between SoCalGas and SDG&E are not, and should not be, subject to the affiliate transactions moratorium.

ORA states that the Commission should continue the ban on affiliate transactions for short-term procurement because the short-term market moves too fast and there is too great of a potential for abusive self-dealing, with little or no possibility for Commission oversight of these types of transactions. However, for long-term transactions, such as long-term PPAs or a turn-key agreement or take-over of a power plant, the Commission should evaluate these transactions under the current affiliate rules. ORA testifies this process should have enough built-in protections to prevent potential self-dealing and other abuses.

TURN states the Commission should extend the ban on affiliate transactions because there still exists the possibility of improper behavior by the IOUs. If the Commission does not extend the ban, then it should require preapproval of affiliate contracts of more than one year's duration and complete disclosure of all affiliate transactions for procurement from affiliated generators or marketers (i.e. no confidentiality would exist, and the utilities must make the contracts publicly available). TURN also states that the utility risk management committees must not contain non-utility corporate officers and the Commission should direct SDG&E to create a risk management committee that only looks at transactions from the utility, i.e. SDG&E's, perspective.

IEP and WPTF do not object to affiliate transactions, preferring them to direct utility participation in generation bidding. CAC/EPUC testifies that participation by utility affiliates will enhance competition and specifically requests that the Commission lift the ban we adopted in D.93-03-021 on SCE procuring new resources from its QF affiliates. CCC states the Commission should not allow utilities to circumvent the procurement process by entering into special affiliate deals, citing SCE's Mountainview application process.

c) Discussion

In this decision, we are setting the market structure and rules for long-term procurement. We are allowing the utilities to directly participate in owning new generation facilities but recognize that we will need to be vigilant in overseeing that no perceived bias occurs in selecting, or dispatching the resources, especially when the current cost recovery mechanisms favor the rate-based power plants. We include utility participation in order to have the assurance of more state control over resources and an effective check against competitive market manipulations and abuses.

We do not have the same level of oversight and authority over affiliate transactions that we do over direct utility operations. We recognize that cross-subsidies and anti-competitive conduct has occurred in the past in affiliate procurement transactions and that it could occur in the future under the market structure we adopt here. The most direct and effective means to avoid any potential conflict of interest is to simply prohibit the transactions.¹⁷ The holding companies and affiliates of each utility should plan for future generation investment to be made outside of the utility's service territory and sold to other load serving entities.¹⁸ Two exceptions we need to address here are the gas storage and transportation transactions that SDG&E needs to conduct with SoCalGas and that PG&E may need to conduct with separate company departments and unregulated affiliates.

d) SDG&E and SoCalGas

SDG&E states that its dealings with its regulated affiliate, SoCalGas, should not be subject to any affiliate transaction rules because SoCalGas is the only provider of natural gas storage and intra-state transportation in Southern California outside SDG&E's service territory and therefore ratepayers receive benefits from these transactions and would be harmed by any restrictions placed on the transactions.

In response to the ALJ's request, SDG&E prepared Exhibits 110C and 132 to describe all procurement transactions that occur between SDG&E and SoCalGas and entered Exhibit 70 to show its risk management committee and the Sempra Energy corporate committees. Exhibit 132 shows that SDG&E purchases transportation and storage services from SoCalGas, for its own procurement as well as an agent for DWR, pursuant to Commission-approved tariffs and filed negotiated rates, as well as pursuant to the 25 "Remedial Measures" adopted as part of the merger between Pacific Enterprises and Enova Corporation (D.98-03-073, Attachment B). Exhibit 110C shows that SDG&E has recommended additional SoCalGas services to DWR.

Exhibit 70 shows (1) that 7 of the 9 members of SDG&E's Electric and Gas Procurement Committee are from Sempra Energy Utilities (SEU), the parent of SoCalGas and SDG&E; (2) Sempra's Energy Risk Management Oversight Committee, the analytical platform supporting enterprise-wide energy risk-management activities, contains members from both the regulated and unregulated affiliates; and (3) Sempra's Project Review Committee, which reviews and approves all transactions in excess of $10 million and commitments with important policy implications, has no members from SDG&E or SoCalGas and only one member from SEU on an 11 member committee.

In 1998, when the Commission approved the merger between Pacific Enterprises and Enova Corporation, California's electric market was under the competitive market structure of AB 1890. The remedial measures adopted then for transactions between SoCalGas and SDG&E should be reexamined in light of today's market structure. For instance, as a condition of approving the merger, the Commission required SDG&E to sell its gas-fired generation plants to nonaffiliates of the merged company, a market power mitigation measure sought by FERC and ORA. Today, the Commission is entertaining a proposal from SDG&E to own a Sempra gas-fired generation plant and has placed SDG&E as agent of DWR contracts with gas-fired generation plants.

In addition, as well as adopting the remedial measures in Attachment B referenced by SDG&E, the Commission in D.98-03-073 ordered the hiring of an independent auditor for a management audit of how the combined utilities operated. One of the concerns found by the auditors, and addressed by the Commission in D.02-09-048, was the sharing of SoCalGas risk management information with a Sempra Energy Trading vice president. The audit was conducted between June of l999 and July of 2000.

Even without the benefit of examples of any harm to SDG&E customers from including Sempra personnel, we find that including such people on a committee to evaluate procurement options for the ratepayers is troubling. Sempra officers have a foot on each side of the firewall, partly representing SDG&E's customers, and partly representing the affiliates. To protect the appearance as well as the fact of affiliate separation, we think there should not be affiliate or holding company personnel involved in utility procurement decisions of the utilities.

We are also troubled by SDG&E's procurement risk management committee being dominated by SEU officers. SDG&E has extremely competent management and it is this management whose duties should include assuring that procurement activities are undertaken in the most appropriate and economical manner.

Therefore, we direct that SD&E file a revised Exhibit 70 to reflect that the risk management committee(s) overseeing SDG&E's electric procurement operations and DWR-related gas procurement operations are comprised solely of SDG&E management. This filing should be by Advice Letter within 30 days.

In D.01-09-056, the Commission reviewed Sempra Energy's September 13, 2000 request to reorganize its regulated California utility businesses to further integrate the management and cultures of SoCalGas and SDG&E and found the proposed functions for shared resources to make business sense. SDG&E was not procuring electricity in the market at the time of this filing and decision. A review of whether negotiated transactions with SoCalGas should be subject to special transaction rules and reporting should be undertaken, especially since SoCalGas' services are under an incentive mechanism while neither SDG&E's electric procurement operations nor its DWR related gas procurement are under an incentive mechanism.

The management audit discussed above should be narrowly focused on two issues: SEU's participation in the risk management committee structure for SDG&E procurement operations; and any rules or reporting needed for SDG&E's energy procurement transactions with SoCalGas. The Commission's Energy Division should draft the scope of work required, select an independent auditor, and oversee the analysis. At the conclusion of the analysis, an analysis report should be filed with the Commission and served on all parties to this proceeding. The auditor should remain available to explain the report's findings, and testify in evidentiary hearings at the Commission on the findings included in the report. These audit costs should be reimbursable. SDG&E should place the costs in a memorandum account.

In Resolution (Res.) E-3838, issued on July 10, 2003, the Commission authorized SDG&E's first Gas Supply Plan for its administration of DWR contracts. In that resolution, we apply the affiliate transaction rules to all procurement transactions between SDG&E and SoCalGas, and set an interim standard for transactions SDG&E enters on behalf of DWR with either itself or an affiliate for services which are paid on a negotiated basis. We should adopt this standard on an interim basis for all SDG&E's procurement transactions.

e) PG&E and Affiliates

In Res. E-3825, adopting a Gas Supply Plan (GSP) for PG&E's administration of the gas tolling arrangements of DWR electricity contracts, the Commission expressed concern that PG&E may engage in inappropriate self-dealing with its affiliate or operating divisions and proposed an interim method for addressing it. Specifically, the Commission stated:

"An additional consideration is the extent that PG&E may engage in inappropriate self dealing with its affiliates or operating divisions. Such abuse is possible since PG&E owns and markets, through its Golden Gate Market Center operation, gas storage (in direct competition with Wild Goose Storage) and intrastate backbone transmission services. As a case in point, PG&E is proposing using parking and lending services with the Golden Gate Market Center under the Gas Supply Plan for managing imbalances. Additionally, PG&E Gas Transmission Northwest, a pipeline connecting western Canadian gas pipelines to the utility's backbone transmission system is controlled by a utility affiliate."

"In D.02-10-062, we adopted standards of behavior that the utilities' must observe in connection with their procurement practices. For transactions with affiliates, Standard of Behavior No. 1 is applicable and specifies the following:^{19 20}

"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 an unaffiliated third party, are prohibited." (D.02-10-062, p. 51, mimeo.)

"To the extent that PG&E will consider using a utility affiliate to provide service for the DWR contracts, it must obtain a waiver from this prohibition through a petition to modify D.02-10-062.

"In cases where PG&E is considering use of its utility owned facilities and services, we are concerned about PG&E's ability to engage in earnest negotiations as an agent of DWR for services offered and provided by the utility.²¹ In some cases there may be competitive alternatives available to PG&E and that the utility has discretion to use its own facilities or those of another provider (e.g., gas storage). A conflict of interest is inherent in such bargaining because the utility has opposing goals to increase utility profits yet protect the interests of DWR, the principal, and minimize costs. To remedy this conflict, we need a standard to gauge whether PG&E's negotiated prices for these services on behalf of DWR are the product of the competing interests of a buyer and seller in an arm's length transaction. An additional factor for consideration are PG&E's request for offers (RFO) and bids received from competitors to provide services. We expect PG&E to seek such bids in all cases where competitive services are available.

"For PG&E's initial Gas Supply Plan, we will adopt the following presumption of reasonableness standard. We will presume in such cases where an RFO is issued and offers are received that a reasonable price is paid if PG&E's charge to DWR for the use of the utility's facilities or services is the same as or lower than the bid(s) received. In cases where there are no competitive alternatives for comparison, we will presume that a reasonable price is paid if PG&E's charge to DWR for the use of the utility's facilities or services is either: 1) the tariff recourse rate for the service; or 2) if the price is negotiated, no higher than the volume weighted average of the price the utility negotiated (except for DWR) for each similar service in the same month and for the same period the service is provided. PG&E will be required to show why any transaction entered into above the weighted average price level was appropriate and reasonable. Whether the utility's decision to use such services was prudent will be considered in our reasonableness review." (Res. E-3825, issued July 10, 2003, pages 18-20.)

The concerns raised in Res. E-3825 apply beyond the GSP to include future electricity procurement by PG&E for its own portfolio. We should establish rules for any dealings with PG&E Gas Transmission Northwest if PG&E needs to deal with this affiliate in order to access Canadian gas pipelines. In cases where PG&E is using its own facilities, we have the same concern with negotiated rates that we discuss earlier for SDG&E and also question whether the limited competitive market for storage services is an appropriate benchmark or whether a cost-based standard should be developed. For dealings with other departments, we should examine any potential for abuse due to different department's costs recovery mechanisms and incentive structures. Therefore, we direct a management audit focused on these procurement issues be undertaken, using the same procedure we specify above for the management audit of SDG&E again, these audit costs are reimbursable; PG&E should place the costs in a memorandum account.

In summary, we adopt here a permanent ban on affiliate transactions for procurement with the following exceptions:

1. "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.

2. Transactions for natural gas services between SDG&E and SoCalGas and between PG&E and affiliates and operating divisions that are found necessary and beneficial for ratepayer interests. These transactions should be subject to the rules adopted in Res. E-3838 and Res. E-3825 pending receipt and review of the management audits ordered here.

K. Financial Capabilities of the Utilities

Each utility's long-term plan shows a need for additional supply-side resources within the next five years, but PG&E's and SCE's recommended plans rely solely on short and medium term contracts to meet their needs, rather than proposing commitments to new or repowered power plants. Both utilities cite their inability to access the capital market at reasonable rates and the need for maximum flexibility due to the lack of clear resolution on the critical issues of direct access policy, community aggregation, and prospects for a core/non-core market structure, as the reasons they are unwilling to make longer term commitments. ORA testifies that PG&E's and SCE's recommended plans rely too much on market purchases and may not have adequate resources to meet their customers' need.

In D.02-10-062, we addressed the utilities' capability to meet their obligation to serve, and found that PG&E and SCE did not need to obtain an investment grade credit rating prior to resuming the procurement role. We addressed each of the arguments raised by PG&E and SCE regarding why they were not capable of resuming full procurement. We found that PG&E and SCE were capable of resuming full procurement and, under their continuing obligation to serve, should do so beginning on January 1, 2003.

Today, the three utilities have all successfully resumed full procurement and the financial prognosis for PG&E and SCE is much improved. SCE has received an investment grade credit rating from Fitch and PG&E anticipates exiting bankruptcy with an investment grade credit rating by the end of this year. We expect each utility to make the investments necessary to meet their obligation to serve their customers at just and reasonable rates.

The uncertainties surrounding direct access policy and the legislature's consideration of core/noncore market structure make procurement planning challenging, especially for long-term commitments. PG&E provided a core/noncore scenario to guide its planning and other utilities should consider this in the next plan filing. We agree with the utilities and other parties that care should be taken not to make commitments that could later result in stranded costs. For their next long-term plan filings, all three utilities should include an appropriate level of long-term commitment to additional power plants or plant-specific purchase power contracts.

The utilities are concerned with the financial and credit implications of any long-term power contracts they may enter into, particular as it affects their long-term prospects of becoming commercially viable. Of the three utilities, only SDG&E has investment grade credit rating. As such, it did not discuss debt equivalency, credit capacity and collateral issues as barriers to its long-term procurement plans. SCE cites the debt equivalency issue and lack of Commission policy on cost recovery issues as barriers to their entering into long-term contracts, while PG&E focuses more on credit capacity and collateral issues.

1. Debt Equivalency

Given the Commission's policy objective of encouraging the IOUs to enter into longer term PPAs, we now turn our attention to the issue of debt equivalency. Debt equivalency is a term used by credit analysts for treating long-term non-debt obligations -- such as PPAs, leases, or other contracts -- as if they were debt. Credit analysts adjust a utility's balance sheet and income statement entries by assigning a debt equivalence amount (in $), expressed as a "risk factor". The risk factor can account for 0% to 100% of a PPA's fixed payments, depending on the type of PPA structure. This dollar amount is used to calculate the financial measures used to assess a utility's credit quality.

The CPA testifies on the limitations of the debt equivalency issue within the context of our procurement proceeding. As a party active in municipal market financing, the California Power Authority states, "debt equivalency is not a cost...in this proceeding, it's a `red herring,' since it represents an accounting entry." The methodology for determining debt equivalency is an accounting treatment, with little implication for cashflow. These observations are underscored by S&P, who state: "Cashflow analysis is the single most critical aspect of all credit rating decisions."²² SCE acknowledges the limitations of the debt equivalency issue as well, saying:

"...higher levels of equity do not necessarily provide ongoing cashflow by themselves. As an additional solution, SCE advocates higher returns on equity or other cash flow enhancements that directly affect financial metrics may be necessary to support credit ratings."²³

Rating agencies use qualitative (i.e. subjective) approaches to assessing debt equivalency. The methodology and risk factor applied varies according to the particular credit rating agency. SCE acknowledges this, saying: "...the rating agencies do not use a uniform approach to determining debt equivalence, and S&P has indicated that its methodology is evolving (our emphasis) in response to changing conditions. Further, not all PPAs are alike. For example, S&P uses a higher risk factor for take-or-pay PPAs than for performance-based PPAs.

a) SCE's Concerns for Long-Term Power Contracts

SCE asks that the Commission take steps to improve and maintain the utility's creditworthiness and financial viability. SCE states that restoring its creditworthiness status is a prerequisite to implementing its long-term procurement plan. In support of its argument, it cites the 2001 Settlement Agreement in which the Commission recognized the importance of SCE regaining creditworthiness as soon as possible, so as to provide reliable electric service.

SCE states that as it takes on additional power contracts and other long-term commitments, its credit rating will decline, undermining its ability to maintain its investment-grade status. To counter this rating decline, SCE asserts that the Commission should add more equity to its capital structure, thereby recognizing debt equivalency costs in rates as well as in overall costs of procurement.

b) Implications for Market Structure

SCE testifies that the rating agencies are looking for the longer term solution to the market structure problem in California, and will only allow an investment grade rating once they are comfortable that a permanent framework is in place and that it works well in the long term.

ORA counters SCE's position, stating: "SCE's current credit rating reflects the state of the regional electricity industry coming out of the electricity crisis, and cannot be blamed on the Commission's cost recovery mechanisms or the debt equivalence impact of long-term contracts with any degree of certainty."²⁴ Credit ratings upgrades often occur due to improvements in general economic or industry conditions. We note that Fitch recently upgraded SCE's credit rating to investment grade.

c) Commission Procurement Policy and Treatment of Debt Equivalency

We find there are limits to the debt equivalency methodology. The debt equivalency issue is an accounting treatment applied to long-term financial commitments. It does not represent a market-driven process for valuing long-term contractual commitments. An assessment of price risk inherently involves market dynamics in valuing these commitments. In the Commission's procurement proceeding, we address issues of economic value, not accounting value, by taking into consideration the relative costs of alternative procurement options. This is implicit in Pub. Util. Code § 454.5(1)(d), which directs the Commission to "assure that each electrical corporation optimizes the value of its overall supply portfolio." To introduce accounting processes into this proceeding might skew our assessment of the relative value of various procurement options.

The rating process is not transparent. SCE acknowledges that S&P is the only rating agency that publishes guidelines for the metrics it uses. There is little discussion of Moody's methodology, so there is no basis on which the Commission can analyze and/or compare the methodologies of the major rating agencies. There is no indication that consensus among the major rating agencies is forthcoming or imminent. In implementing a debt equivalency policy, the Commission would look for an industry standard as a benchmark on which we can base our policy.

Furthermore, while credit ratings may look the same, their computations are based on non-uniform qualitative factors, hence the potential for confusion. An "A" rating from S&P is based on a different analysis than the "A" rating from Moody's. Thus, the utilities' somewhat overstate the case for Commission policy as a means to garner a particular credit rating. Moody's says that the "same rating from different agencies only looks the same." Further, it adds that, "...ratings are opinions about risk, not formulas. Accurate, forward-looking credit analysis cannot be mechanized. As a borrower, you cannot assume that a rating from any agency will provide the same degree of access to the sources of investor capital."²⁵

The credit rating process is a dynamic process. The utilities have not taken into account the impact of general economic and industry conditions over rating changes. As ORA notes:

"The utilities have failed to demonstrate any correlation between entering long-term contracts and credit ratings. In fact the health of the entire electricity market, more than micro-factors such as cost recovery mechanism and specific contract terms determines the utilities' credit ratings."²⁶

"SCE implicitly agrees, stating that "The business position....has to do with evaluating the environment in which a company operates in, so that would include the political and regulatory environment, the ability for a company to make business decisions and pursue them without obstacles." SCE adds that "The ability of the company to pursue their business in a manner that will mitigate the business risks that they encounter really defines the business risk number that S&P comes up with."²⁷

Seeing no consensus regarding the methodology and application of debt equivalency, we believe that implementing a Commission policy at this time would be premature and over-reaching. The Commission has previously examined debt equivalency in its Cost of Capital proceedings. (See D.92-11-049 and D.93-12-022.) The utilities should make a showing for specific relief in their upcoming cost of capital filings.

2. Cost of Collateral

The long-term power contracts that utilities will enter into must be supported by collateral. PG&E and SCE state that their ability to secure reasonably priced financing for these contracts is hindered because of (1) SCE's non-investment-grade rating and (2) PG&E's bankruptcy status. Given their financial duress, , each argues that their financial status precludes them from committing to long-term contracts and limits the procurement options available to them.

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 cost of capital proceeding is the first forum SCE should raise this issue.

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 does not expect to be able to enter into long-term contracts while 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."

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 decisionmaking. In our earlier discussion of debt equivalency, we referred issues affecting utilities' capital structure to the Cost of Capital proceeding. We reiterate that position here.

It is essential to balance the cost of collateral against the risk of counterparty default. PG&E and SCE currently have non-investment credit ratings, 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. We note that should exposure exceed a predetermined limit or a counterparty fail to supply energy when required, ratepayers will suffer the consequences.

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. Nonetheless, we must act on behalf of ratepayers to protect them from the adverse impact of counterparty non-performance, as it relates to cost exposure and/or lack of reliable supply. 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.

⁷ 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. "

²⁶ ORA OB 9/15, p. 5.