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 it regulates will provide reliable service at least cost. This involves determining an appropriate demand forecast 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 weather9 or unexpected plant outages. "Resource adequacy" seeks to address these same issues. 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 assuring that capacity is available when and where it is needed.
In this decision, the Commission (1) directs that each Load Serving Entity (LSE) within the utility's service territory (i.e., utility, Energy Service Provider (ESP) or Community Choice Aggregator) has an obligation to acquire sufficient reserves for its customer's load located; (2) adopts a reserve margin for LSEs of 15-17%; (3) directs the LSEs to meet this 15-17% reserve requirement by no later than January 1, 2008, through a gradual phase-in including the establishment of interim benchmarks to become effective in 2005; (4) establishes a requirement that utilities forward contract 90% of their summer (May through September) peaking needs (loads plus planning reserves) a year in advance;10 and (5) continues the 5% target limitation on utilities' reliance on the spot market (i.e., Day-Ahead, Hour-Ahead, and Real-Time energy) to meet their energy needs.11
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 on these workshops, particularly on the issue of counting resources, including 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, consistent with the ISO Board's adopted motion,12 the long-term DWR contracts. Once consistent methodologies are developed, the Commission will work with the ISO and other interested parties to develop appropriate reporting requirements. In the interim, the ISO can continue to monitor the utilities' procurement activities through their on-going involvement (including access to confidential data) of the utilities' on-going procurement related filings. This decision also addresses other miscellaneous issues associated with resource adequacy including deliverability, penalties, and day-ahead commitment. In previous decisions in this proceeding (D.02-12-074 and D.03-06-067), the Commission has already addressed the issue of penalty provisions associated with a utilities' failure to follow its established procurement standards.
2. California Should be Responsible for Determining its Energy Future
Resource procurement inherently involves numerous policy decisions that have significant implications for the cost and portfolio structure of resources used to meet California's energy needs. Given the strong interaction between resource procurement and resource adequacy, it is desirable that California policy-makers have the necessary decision-making authority. It is for this reason that the Commission believes that it should be responsible for addressing resource adequacy for the roughly 90% of the ISO load located within the utilities' service territories. As the ISO notes:
"[It] is not aware of any other entity besides the CPUC and/or local regulatory authorities (e.g., municipal boards) that can currently impose planning reserve/resource adequacy requirements. Accordingly, the CA ISO considers that the CPUC should clearly define planning reserve/resource requirements for these loads in a manner that is equitable and assures consistent treatment and requirements."
The Commission has routinely advocated, in a variety of forums, that it should address resource adequacy and procurement issues. This position has now been acknowledged by both FERC and the ISO.
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..."13
FERC, in its recent October 28th 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).14
Similarly, the ISO has recognized that resource procurement is primarily a state function, and adopted at its November 21, 2002 Board meeting, a resolution to defer consideration of its resource adequacy proposal while directing ISO staff to actively participate in this proceeding at the Commission.
With regard to municipal utilities, as the Commission, the ISO,15 and CEC16 have all recently noted, such utilities have traditionally provided reliable service including provision of adequate reserves and have availed themselves of other regulatory options to address resource adequacy.17 Additionally, the CEC is engaged in collaborative processes with the municipal utilities to address this issue.
3. Policy Issues
While virtually all parties in this proceeding agree that it is critical for the state to ensure adequate reserves and to address resource adequacy, there are a number of policy issues that must be resolved first.
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.18 As SDG&E calculated, each additional 1% increase in reserve level adds $2.8 million to its costs.
Second, there is 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 scope of this proceeding, established a "loading order" for new resource additions emphasizing increased energy efficiency, demand response/dynamic pricing, and renewable energy. The development, timing, and calculation of a reserve level can have a significant effect in promoting (or deterring) development of these new resources. As FERC recently noted in its order on the ISO's proposed redesign of the California wholesale electric market:
"[R]ushing to relieve inadequate regional supplies and reduce high regional spot prices may bias construction choices toward supply resources that can be constructed quickly, perhaps sacrificing long-term cost minimization, environmental concerns and fuel diversity goals." 19
An appropriate balance should be achieved between meeting reserve requirements expeditiously while seeking to optimize the resource mix/portfolio. Paradoxically, rushing to implement a reserve requirement might further increase California's reliance on natural-gas fired resources, posing a different set of reliability concerns if there are supply constraints or price spikes for this fuel.
Third, there is the issue of reliance on the spot market to meet a portion of reserve requirements. While no party advocates extensive reliance on the spot market, most 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, a practice that some utilities responsibly engaged in under pre-AB1890 resource procurement.
Fourth, there is the need to ensure that in establishing reserve requirements, we are not creating a potential for the collusion or exercise of market power in the forward markets for capacity. Unlike spot markets, such as the ISO's existing hour-ahead (and soon to be established day-ahead market), there are significantly fewer safeguards and opportunities for regulatory review by FERC of forward market transactions. FERC's recent order denying rehearing of California's request to find that the DWR contracts were not "just and reasonable" emphasizes the high burden of proof needed to challenge the reasonableness of forward market contracts.
Fifth, there is the need to evaluate resource adequacy in the context of the broader regional energy markets and under which design rules these markets will operate. 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 in conjunction with these efforts, not only in the area of scheduling and timing, but also as a complement to effective market mitigation rules. Additionally, the Western energy markets outside of California have neither functioning ISOs nor any resource adequacy or capacity market requirements. Therefore, in adopting resource adequacy requirements, we must ensure that we are not unilaterally imposing burdens upon California's utilities -and by extension California's economy - to which utilities located outside of California are not subjected.
Based on the above concerns, we believe that the best way to achieve these goals is for California to set, control, and enforce its resource adequacy policies at the state level.
4. Current and Forecasted Market Conditions
A key factor for consideration in evaluating resource adequacy is the current state of the wholesale energy market in the West, and the degree to which California's utilities have obtained or can access these resources to meet their energy needs. Many of the parties believe that adequate reserves should exist until around the year 2008. A late-filed exhibit, consolidating each utilities' resource needs and comparing it to available supplies, concluded that:
"[T]here appears to be sufficient existing, and highly probable new generation, located outside of California or importable over existing transmission ties, to meet IOU reliability needs (including a 15% reserve requirement) over the time period 2004-2010."20
PG&E believes that sufficient resources will be available to California to meet its requirements until around 2010. Equally important, almost all parties believe that there are ample amounts of resources available for California to meet its resource needs for 2004, thus providing the Commission a window to develop an optimal resource procurement strategy.
Based on its review of the California energy market, the CEC believes that new capacity needs are unlikely to occur until 2007, at the earliest. As the CEC also notes, its review and 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 even further into the future the need for new resources. These conclusions are consistent with the CEC's Integrated Energy Policy Report (IEPR) adopted in November 2003. The CEC expresses the concern that focusing on reserve levels based only on generating resources may bias planning decisions to the detriment of demand-side resource options. According to the CEC, the successful implementation of additional energy efficiency and demand response programs can allow California to maintain sufficient reserves even further into the future , that is, beyond the 2007-2008 timeframe, even if there is little or no new generation being built. For example, the CEC's IEPR forecast does not include the additional procurement-related energy efficiency funding the Commission approved in this docket on December 18th in D.03-12-062, expected to total 950 MW over five years.
In its recently issued decision addressing SCE's application SCE to enter into a Purchase Power Agreement with the 1,054 MW Mountainview power plant project, the Commission concluded that:
SCE has forecast that considering its existing resource base of utility-owned generation, QF contracts, interutility contracts, Department of Water Resources (DWR) allocated contracts, and transitional contracts, when combined with expiring contracts, forecasted load growth, and the assumed reserve requirements, it will need more capacity by 2006. SCE does admit that there are existing uncommitted resources to meet any gaps between now and 2006. However, moving forward, SCE forecasts a need for dispatchable, peaking and intermediate resources in the short-term, and baseload over the long term. Mountainview with its 1,054 MW combined-cycle, in SCE's service territory capacity satisfies this resource need. We make this finding independently of any finding concerning the future of Mohave, or QF contracts. (D.03-12-059, p. 33, emphasis added.)
The ISO and CPA, by contrast, expect that capacity constraints could appear earlier than 2007, and that setting a reserve requirement will assist in ensuring that existing resources remain available for use.21 IEP and WPTF make somewhat similar points, arguing that ensuring the availability of existing resources should be considered in setting reserve levels.
Based on the assessments described above, we conclude that there are ample resources for California to meet demand for 2004 as well as adequate resources available for California to meet peak demand through 2007 although all of these forecasts, particularly in the "out" years, contain some element of uncertainty.
5. Appropriate Reserve Levels and
Phase-in Period
The relative balance between California's energy needs and the resources available to meet them is important in determining the procurement strategies of the utilities' in acquiring reserves.
In D.03-12-062 the Commission adopted the Joint Recommendation's statement that reliable operation of the electric system requires two types of reserves - operating reserves and planning reserves. 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.22 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 outages, fuel limitations, or in the case of hydroelectric power, insufficient water.
The Joint Recommendation defined planning reserves and operating reserves as follows:
· Planning Reserve Margin ("PRM"): The reserve margin shall be an obligation over and above the capacity required to meet peak demand. PRM is computed as follows: PRM = [ (Dependable Capacity/Peak Load) - 1] x 100%. In calculating PRM, "Dependable Capacity" shall not be reduced to reflect Reasonably Expected Resource Outages.23
· Operating Reserve Margin ("ORM"): ORM shall be used for purposes of reviewing resource adequacy over a shorter term, such as a year or less and shall be applicable to short term procurement plans. ORM is computed as follows: ORM = { [ (Dependable Capacity - Reasonably Expected Resource Outages)/Peak Load] - 1} x 100%.
While virtually all parties agree that it is appropriate to set a longer-term planning reserve level, parties disagree over both the level and whether a phase-in period should be used to achieve it. In D.02-12-074, the Commission provisionally adopted a 15% reserve level subject to further revision in this proceeding.
The Joint Recommendation24 proposes a 15% planning reserve, phased in starting in 2005 and ramping up through 2008, based on equal percentage increments (i.e., 2% per annum increase). For 2004, the utilities will meet the 7% operating reserve level required of the ISO, as approved by this Commission in D.03-12-062.
The CPA recommends the adoption of a 17% reserve level, based upon a study it conducted and that was officially noticed as part of the record in this proceeding. The ISO supports the 17% reserve level, and also supports a three-year phase in to achieve this level, provided that the utilities meet a 90% year-ahead and 100% month-ahead capacity requirement. The ISO notes that a three-year phase-in would help alleviate concerns over the exercise of market power in the forward market. Finally, IEP supports the 17% reserve level, while WPTF states that the reserve level should be "at least 15%."
Based upon the record developed in this proceeding, we believe that a planning reserve level of between 15-17% should be adopted for all LSEs, which should be phased in by no later than January 1, 2008, as we are essentially adopting the target level proposed by the Joint Recommendation. In their procurement fillings, the utilities should justify any reserve levels above 15%. We recognize that there is an inherent "lumpiness" to resource additions and the utilities may end up with reserve levels above 15% depending upon the timing of resource additions.
In approving a 15-17% planning reserve we carefully considered the CPA's proposal for a 17% reserve level. We note the concerns of many parties that the CPA's analysis may contain overly pessimistic assumptions about the shape of the future market and we note that the ISO found that additional utility-specific analysis is needed to determine an appropriate forced outage rate, a key determinant for setting an appropriate reserve level.25, 26
A 15-17% reserve level should provide not only reliable service but also an additional margin of safety. As PG&E states:
"Based upon the simulations performed by Henwood, a 15% reserve requirement produces a 2006 loss of load probability of 0.2 days in 10 years."
* * *
"TURN witness Woodruff concurs that a 15% planning reserve level would result in a "one day in fifty years" generation reliability criteria and that this level of reliability is reasonable.27
SCE and SDG&E reach similar conclusions. A 15% reserve level is also the minimum level that the ISO determined would provide reliable service when setting standards for municipal utilities to become metered subsystems (MSS) under its tariffs.28
With regard to an appropriate phase-in period, the utilities and LSEs should meet this 15-17% requirement by no later than January 1, 2008, with interim benchmarks established starting in 2005. The starting point for compliance will be determine in the workshops. While these are minimum standards, the utilities should justify proposed reserve levels above 15% in their procurement filings and explain why reserve margins higher than 15% would be appropriate.
A 15-17% reserve level, phased in by 2008, ensures reliable service by providing incentives to encourage the retention of existing resources and avoids setting reserves at levels that could require the utilities to make short-term investment decisions inconsistent with the Energy Action Plan's preferred "loading order" of new resources. For example, imposing a high reserve level quickly might require utilities to enter into longer-term contracts for capacity, thus crowding out preferred resources, such as demand response and energy efficiency, which are currently propose to come on line in significant quantities in 2006 and beyond.
As several parties noted in response to the Proposed Decisions, a too-rapid implementation of a reserve requirement could create a "gold-rush" with utilities forced to sign-up all available capacity in order to meet their reserve requirements. Additionally, there is almost 3,000 MW of capacity that is currently required to be offered to the marketplace through 2006 as part of a settlement regarding market manipulation in the California energy market. Setting a reserve requirement either too high or reaching it too quickly could result in California utilities potentially having to pay excess amounts to acquire these resources that otherwise would be offered at cost to the market as compensation for past abuses.
In its Standard Market Design (SMD) proposal, FERC recognized that it is appropriate to phase in any resource adequacy requirement in order to allow entities time to meet the requirement and to prevent the exercise of market power. In its SMD proposal, FERC recognized that a 3-5 year period, with interim benchmarks, was acceptable,29 and FERC's recommendation is consistent with the four year phase-in period adopted here.
By having the Commission set the phase-in period, we retain the ability to quickly revise the reserve benchmarks should market power prove to be a problem. In their original resource adequacy proposal, and in their testimony in this proceeding, the ISO is not proposing to place any price caps or restrictions upon the prices charged for capacity.30 Setting a reserve requirement imposes an asymmetrical obligation on market participants, where LSEs are obligated to procure capacity or face potential penalties, yet suppliers have no corresponding obligation to offer capacity at reasonable prices. Therefore, the Commission retains the right to adjust the phase-in period as necessary to protect against market power abuses.
Finally, a phase-in period recognizes that prioritizing each utility's need may be appropriate, given their current financial resources. In not proposing to set any restrictions on capacity prices in the wholesale energy market, the ISO believes that the cost of building new generation would serve as a de facto price cap on capacity prices. While such a conclusion may be reasonable for capacity markets such as PJM or New York, where import/export capabilities are limited and most capacity needs are self-provided, such a conclusion may not be applicable to the California market which has a significant amount of divested generation, expiring QF contracts, and reliance on imports. Higher prices in the capacity markets from a too rapid implementation of a reserve requirement could limit the amount of funds that California's utilities would have available to meet other Commission goals such as achievement of the Renewable Portfolio Standard.
In setting the target of 15-17% by the beginning of 2008, we do not believe that we are setting a reserve level that will be difficult for the utilities to achieve. WPTF observed that each of the utilities' original filings proposed target reserve levels in the 15-17% range to be achieved by the 2005 time period.31
Additionally, although several parties were opposed to the Joint Recommendation's proposal that each utility only meet the ISO's proposed 7% operating reserve requirement for 2004, a closer look at the utilities' filings shows that their actual planning reserve margins for 2004 were significantly above the 7% minimum. SDG&E's testimony, for example, showed that it possessed sufficient capacity, either owned or under contract, to easily meet the 7% operating reserve requirement, implying that SDG&E's actual planning reserve levels were well above 7%. A review of SCE's filing shows that, in determining its resource needs, it had already included in its calculation estimates of expected plant availability, a major component of a planning reserve level, as well as excluded its interruptible load programs in calculating its reserve level. Thus, SCE's actual planning reserve margin would appear to be significantly higher, perhaps in the 12-13% range, for 2004. Only for PG&E does it appear that there might be some over-reliance on spot purchases, but again PG&E's original filing did not include its subsequent procurement efforts, approved by the Commission, to firm up a significant portion of its outstanding short position.32
6. 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., annual peak load plus the target reserve level) a year in advance and 100% of their monthly peak capacity need plus reserves a month in advance. SCE and PG&E specifically opposed this proposal. The Joint Recommendation proposes that the utilities can rely on "spot capacity" purchases for 2004, and that, going-forward, some reliance upon "spot capacity" may be appropriate. In addressing this issue we note that there is no analytical support behind the ISO's proposed benchmarks. As the ISO's own witness noted, the 90% figure was a number within a range and that other numbers, such as 85% might be equally appropriate. 33
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, in order to respect confidentiality concerns, it appears that for many months of the year (particularly off-peak or shoulder months) 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 periods during the 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 the time of their filings.
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 enough to minimize the incentives for generators to engage in physical or economic withholding.34
Equally important, as PG&E and SCE note, imposing a mandatory percentage of forward contracting is inconsistent with the risk assessment models the utilities are supposed to develop and use to measure and report ratepayer risk exposure.35 The purpose of these models is to measure utility portfolio price risk exposure vis-à-vis consumer risk tolerance. Thus, the application of these models should inherently result in utilities seeking to forward contract to a significant extent, to minimize exposure to any high prices or reduced reliability from 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. Supporters of the Joint Recommendation raise a similar issue, namely that in advocating for the utilities to procure some portion of their capacity needs in the spot capacity markets they do not mean purchasing all of this need in the day-ahead/real-time markets, but instead that these purchases would occur in a continuum, based on market and supply/demand conditions, presumably between the year-ahead and hour-ahead markets. It is therefore unclear what, if any, distinction exists with regard to reliability, if a utility contracts for its needs only 9 to 10 months in advance instead of 12 months.
However, given that for many months there appears to be a relatively small difference between the current de facto level of forward contracting and the 90% level, we do not see a need to adopt the 90% level on a year-round basis. However, we are concerned that sufficient resources be available during the peak summer months when the utilities are more exposed to the market and prices are likely to be higher. Therefore, we will require the utilities to forward contract for 90% of their summer monthly peak needs. Because of the inherent uncertainty as to when hot weather may occur, we define the summer peak period more broadly than suggested by some parties such that it includes the entire months of May through September.
The question we need to decide is whether this 90% level should be a target or a requirement. To help promote reliability, we will make this a requirement for the utilities but will allow the utilities the flexibility to justify to the Commission the need to dip below this level on a case-by-case basis. Thus, the 90% level serves as a benchmark and further safeguard operating in conjunction with each utilities' risk assessment models. Granting the utilities some flexibility provides protection against the exercise of market power in the forward capacity markets, a concern noted by many parties, including the ISO. It also allows the utilities to account for unusual market conditions. Because of the difference between the existing level of forward contracting (70-100%) and the proposed target, utility compliance with this level appears feasible. Establishing this requirement for 2004 is unrealistic and therefore, it is appropriate to defer implementation of this requirement to the beginning of 2005.
The ISO is the only party that proposes that utilities' forward contract for 100% of their needs month ahead, a position opposed by other parties. The ISO provided no economic analysis as to either the increased cost of implementing this proposal or what incremental effects it would have on improving reliability. The reasoning behind the ISO's proposal appears to be based on resource adequacy programs adopted in other parts of the country, such as the PJM pool and New York ISO which impose similar requirements. However, while these other ISOs are largely self-contained, with limited import/export capability, it is unclear how such a requirement would be imposed upon California. Historically, California has relied on, and benefited from, the diversity of load throughout the Western United States, much of which is still provided by vertically-integrated utilities. Because not all of these utilities generally peak at the same time, at any given moment there are usually surplus energy resources available for purchase. These same utilities, however, would be reluctant to commit these resources to California a month in advance, since they will not know when their respective peak demands are likely to occur. The ISO addressed this issue recently when it modified its rules to encourage out-of-state energy resources to increase their level of bidding into the ISO's hour-ahead market, recognizing that these exceedingly short-term resources are useful in ensuring the provision of reliable service.
Imposing a month-ahead requirement at this time is therefore likely to limit opportunities for California to take advantage of this diversity and result in higher prices. As the Joint Recommendation notes, it appears that utilities can rely upon uncommitted supplies for a portion of their energy needs while still ensuring reliable service. A late-filed exhibit by PG&E noted that prior to AB1890 it often included uncommitted capacity (i.e., capacity that PG&E expected to be available but was not under contract) in its resource plans. 36
The Joint Recommendation cautions that the degree of reliance upon this capacity needs to be carefully evaluated. In large part, this depends upon the shape of the underlying market and expected availability. A better approach to ensuring reliable service is to limit each utility's reliance on spot market purchases less than a month in advance to be based on reasonable (and perhaps even conservative) estimates of the energy available in this market.37 For example, we do not want all three utilities assuming they will be able to acquire the same surplus energy from the Pacific Northwest. Thus, reasonable estimates, taking into account expected loads/resources in the Western region, and the procurement strategies of energy purchasers in the West would be helpful to define a reasonable estimate of appropriate reliance on the short-term energy markets. It is precisely this sort of issue that the CEC is examining as part of the Western Resources Assessment Team (WRAT) and as part of its IEPR process.38 This issue will also be further addressed in workshops.
In not adopting the ISO's request we are not advocating extensive reliance upon the spot market. In D.02-10-062 the Commission adopted a target limitation on spot purchases to less than 5%. This limit was to provide a balance between flexibility and reliability. This is a reasonable limitation and additional safeguard which should continue in the utilities' current procurement practices. Additionally, we will allow the utilities' to continue to rely on short-term and spot market purchases to meet their energy needs but only if they have met their capacity requirements in advance. Thus, if the utility has sufficient reserves under contract to ensure resource adequacy but can tap the spot markets in real time at a cost below its call options on contracts, the utility can go beyond this 5% threshold for energy.
It is also important to examine the rationale behind the ISO's proposal. The ISO is proposing not only that LSEs acquire 100% of their needs a month in advance, but that the ability to dispatch and operate these resources also be turned over to the ISO in the day-ahead market. As PG&E notes, this could result in resources acquired by PG&E being used to meet the needs of any other entity within the ISO such as SCE, the City of Roseville, or theoretically even merchant generators wheeling power through the ISO grid. This "pooling" approach to dispatching resources runs counter to the Commission's findings in D.02-09-053, when it rejected a proposal to jointly dispatch the DWR contracts and instead emphasized the importance of each utility operating and managing its own resource portfolio.
SCE notes that while it supports in concept the notion that resources should be made available in the day-ahead market for dispatch, such a requirement might better be achieved through the ISO's tariffs and market rules, and not through imposing it as a requirement of a contract. Additionally SCE notes that such a requirement cannot legally be imposed upon either its QF resources or upon most of their existing DWR contract resources due to contractual limitations. In its comments to the ISO and FERC, the Commission has raised similar concerns, noting that this again imposes an asymmetrical obligation upon LSEs. LSEs are obligated to acquire resources and then turn dispatch decisions over to the ISO while there is no similar obligation directly imposed upon energy resources within the ISO grid.
It is premature at this time to impose a 100% month ahead requirement upon California utilities when there is no similar requirement upon any other utilities within the West and the ISO's final market rules are still in development. We realize that part of the ISO's desire to impose this month-ahead obligation is the perceived uncertainty over whether FERC will continue its current real-time must-offer obligation and/or extend it to the day-ahead market as the ISO has requested. The Commission's position has been that a must-offer requirement is a valid and reasonable condition to impose upon generators. If and when a region-wide resource adequacy framework is developed for the West, then a 100% month-ahead requirement may make sense. In the interim, it is likely to have the effect of limiting California's procurement choices and putting California consumers at a disadvantage relative to consumers in other states. For the foregoing reasons, we do not adopt a month-ahead procurement requirement.
7. LSE Obligation to Procure Reserves for all Load and Customers that it Serves
Today's decision requires each LSE within the utilities' service territories to be responsible for procuring, under Commission oversight, sufficient reserves to provide reliable service to its load.
Virtually all parties that addressed the issue agree that ensuring adequate reserves for all load within the utilities' service territory is a critical and important issue. The Joint Recommendation, for example:
"...[A]gree[s] that capacity and reserve requirements must apply to both IOU bundled customers and Direct Access and Community Aggregation customers, regardless of what entities are ultimately responsible for acquiring the capacity and reserves."39
There was disagreement among the parties, however, as to the appropriate entities that would be responsible for achieving and implementing this goal. Even the Joint Recommendation did not reach a consensus viewpoint on this issue.40
WPTF and SDG&E believe that either FERC or the ISO should have this responsibility for all load-serving entities, including the utilities. PG&E appears to suggest that the ISO should perform this duty only for the ESPs. Both of these approaches would conflict with the Commission's position, filed in comments before FERC, that resource procurement is fundamentally an issue of state, not federal, concern, and that imposition of a resource adequacy requirement would infringe upon the state's right to self determination on this issue. It is inconsistent with both FERC and the ISO's stated policies of giving deference to states to address resource adequacy issues.
Adopting either of these approaches would also preclude the Legislature from addressing this issue as well. To date, both of the major legislative proposals to change the existing market structure (AB 428 and SB 888) specify that the Commission should address resource adequacy issues.
TURN notes the jurisdictional confusion that would arise from having the ISO seek to enforce CPUC-adopted reserve requirements. This would put the ISO in the position of enforcing rules it did not create. Additionally, it is unclear how the ISO could enforce these rules without doing so under FERC-approved tariffs, thus transferring final decision-making authority over California's energy future away from California to Washington. As an example of the potential conflict between federal and state regulation, some of the parties advocating that resource adequacy should be addressed at the federal level are the same parties who have argued against allowing the "preferred resources" identified in the Energy Action Plan (such as energy efficiency) from being counted toward meeting any resource adequacy requirement, thus negating their value and biasing resource decisions towards generation resources. 41
The preferred approach is for California to address the resource adequacy at the state level. TURN, the ISO, and SCE all recognized that the state is the appropriate entity to address reserve issues.
In determining how the Commission should address this issue, two approaches were proposed. They are:
· Each LSE in the utility service territory (utility, ESP, community choice aggregator) would be responsible for acquiring its own reserves needed to ensure reliable service; or,
· The utility would acquire reserves for all load within its service territory including that of ESPs and community choice aggregators.
Putting aside the issue of jurisdiction, almost all parties expressing an opinion on this issue, except SDG&E,42 believe that the preferred approach is to require each LSE to be individually responsible for acquiring its own reserves. This approach would be administratively more simple, allow each LSE to decide how to best meet Commission-imposed requirements, and properly assign responsibility for providing reliable service.
The major impediment to implementing this approach is a perceived concern as to whether the Commission currently has the jurisdictional authority to impose resource adequacy requirements upon ESPs and community choice aggregators. PG&E, SDG&E, SCE, and TURN all believe that the Commission has the requisite authority. ARM and WPTF do not. SDG&E and SCE both note that the Commission could impose reserve requirements upon non-utility LSEs (such as Energy Service Providers or ESPs) under the requirements of Pub. Util. Code § 394. This code section allows the Commission to determine that ESPs demonstrate "technical and operational reliability" and "financial viability." Similar legislative requirements apply to community aggregators as well. Under the requirements of AB 117, community aggregators must demonstrate both "reliability" (Pub. Util. Code § 366.2(c)(4)(b) as well as "any other requirements established by state law or by the Commission concerning aggregated service" (Pub. Util. Code § 366.2 (c)(4)(D). Requiring an ESP or community aggregator to acquire adequate reserves in order to ensure reliable service would appear to clearly fall within this legislative authority.43
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."
ARM and WPTF dispute this contention, relying primarily upon Commission decisions D.98-03-072 and D.99-05-03444 where the Commission initially defined an ESP's responsibilities under the requirements of Pub. Util. Code § 394. In both of these decisions, the Commission chose to narrowly define its jurisdiction, allowing an ESP to meet the requirements of Pub. Util. Code § 394 primarily by proving it had the technical capabilities to interact with the utilities' billing and metering systems and the ISO's scheduling protocols. This latter function was verified through an ESP either becoming or contracting with an ISO Scheduling Coordinator (SC). ARM/WPTF also state that imposing a reserve requirement upon ESPs would conflict with the "terms and conditions" under which direct access customers take service that is not allowed under Pub. Util. Code § 394.45
In reviewing ARM/WPTF's claims, we are unpersuaded that the Commission does not have the authority, if it chooses to exercise it, to impose broader reliability requirements upon ESPs, such as a resource adequacy requirement. Although the Commission chose to narrowly limit the exercise of its jurisdiction in implementing Pub. Util. Code § 394, it is a well-settled legal principle that there is no legal or statutory prohibition against the Commission revisiting and revising its authority in a subsequent proceeding. As SCE states: "If the Commission can develop those standards, it can certainly modify those standards if there is a need to ensure reliability."46 This is particularly true when the circumstances upon which the original decisions were based have changed.
At the time that both D.98-03-072 and D.99-05-034 were issued, the underlying assumption of the Commission was that reliability in the electric markets could be achieved by market mechanisms such as the Power Exchange and ISO.47 Subsequent events have proven that this may not occur absent proper safeguards. During the tight energy supplies and market manipulation of the California energy crisis, for example, high energy prices created financial problems for ESPs, which were then unable to provide reliable service to their customers.48 The level of direct access load falling from 15% to 2%, with the result that the utilities, and later DWR, were obligated to assume the procurement of energy for many of their customers. Separately, as TURN notes, it is not clear if ESPs have the appropriate financial incentives to ensure reliable service under adverse conditions. Thus it would be appropriate if the Commission were to decide that additional safeguards should be imposed upon ESPs under the requirements of Pub. Util. Code § 394.49
We do not find that requiring ESPs to meet a reliability obligation under Pub. Util. Code § 394) would conflict with the "terms and conditions" under which direct access customers receive service. In setting a requirement upon ESPs, the Commission is not affecting any of the contractual relationships between the ESP and the direct access customer. The ESP remains free to request whatever pricing and other terms it desires from the customer. One of the main purposes of a reliability requirement, by contrast, is to ensure that the failure of an ESP to procure sufficient reserves does not affect all other customers on the grid.
Another proposal offered by TURN would require that the utilities acquire sufficient reserves to meet the needs of all customers within their service territories. TURN argues that this approach is consistent with how the utilities have traditionally procured resources to meet the needs of their customers. In procuring reserves in order to provide reliable service, the utility traditionally had to factor in the potential that other market participants would either under-procure or lean on the system, thus requiring the utility to acquire additional reserves in order to ensure reliable service to its customers.50
TURN argues that under existing law the utilities remain both the default provider and provider of last resort for all load within their service territory. Thus, when the level of direct access load shrank from 15% to 2% during the energy crisis, it was the utilities that were obligated to acquire energy to meet the needs of these customers. TURN argues that it is prudent to have the utilities acquire reserves to plan for such a contingency. SDG&E also stated that having utilities acquire reserves for all of the customers in their service territory was legally supportable under the Commission's obligation to ensure that utilities provide reliable service.51
As TURN and ARM/WPTF both note, ESPs appear to generally rely on short- to mid-term contracts to meet their energy needs. In support of its proposal, TURN states that given the changing and fluid customer base that most ESPs utilize, ESPs may not have sufficient incentives to acquire necessary reserves.
It is noteworthy that TURN's proposal is consistent with the approach to addressing resource adequacy issues envisioned in AB 428.52 Under the proposed requirements of AB 428:
"...[T]he commission [in consultation with the CEC and ISO] shall establish resource adequacy requirements that ensure the availability of planning reserves sufficient to serve all customers of the corporation, including noncore and community choice aggregation customers. The resource adequacy requirements shall ensure cost recovery by the electrical corporation for acquired reserves through a nonbypassable component of the electrical corporation's transmission and distribution charges." (AB 428, proposed PU367.6 (i).)
TURN's proposal also acknowledges that the utilities (and their customers) should not subsidize ESPs. It therefore proposes a non-bypassable surcharge so that all customers within the utility service territory pay their fair share of the costs of acquiring needed reserves. Such a surcharge should be similar to existing surcharges already approved by the Commission, such as SCE's Historic Procurement Charge (HPC) approved in D.02-07-032 and the Cost Responsibility Surcharge (CRS) approved by the Commission in, among other decisions, D.03-07-030. TURN also proposes to allow ESPs who have acquired sufficient reserves to "opt-out" of paying this surcharge.
Although the original proposed decision issued in this proceeding advocated the adoption of the TURN approach, PG&E, SCE, and other parties raised several valid implementation issues with TURN's proposal in their comments. These parties' primary concern was that the utilities would be left with the cost of acquiring resources for ESPs that they might not be able to collect from the ESPs, and that it would be difficult to procure resources over a longer time-period if ESPs could "opt-out" of the program on a yearly basis.
While these implementation issues are not insurmountable, and could potentially be resolved through the workshop process, in this decision we have determined that the most simple, most direct, and most efficient approach is that the Commission shall require each LSE to be directly responsible for acquiring their own reserves. As noted, this approach is legally supportable and consistent with the requirements of Pub. Util. Code § 394 (for ESPs) and AB117 (for Community Choice Aggregators).
8. Issues to be Addressed in Workshops
This decision begins the process for the Commission to formalize its resource procurement processes to explain how it will create a resource adequacy framework.
The Joint Recommendation proposes that:
"The Commission should immediately initiate a parallel process to develop a permanent resource adequacy framework...[and] to initiate a collaborative process to develop such a framework and submit a joint report to the Commission no later than January 15, 2004."53
The ISO also supported the need for workshops.54
On September 22, 2003 an Assigned Commissioner/ALJ Ruling "establishe[d] a workshop process to address the technical details of specific resource adequacy issues" with:
"[T]he scope of the workshop...confined to the more technical aspects of this issue, namely the issues of how Load Serving Entities (LSEs) forecast demand, and how supply resources should be valued and considered in assessing an LSEs' resource adequacy."55
The Ruling envisioned use of a Commission-generated questionnaire, followed by a workshop, with the potential for additional workshops if needed.
In setting the scope of the workshop, the Assigned Commissioner/ALJ Ruling recognized that there were numerous threshold policy issues that the Commission first needed to resolve before it could develop a permanent resource adequacy framework. Many of these issues are addressed in today's decision, including jurisdictional responsibility for resource adequacy, appropriate reserve levels and phase-in period, and treatment of direct access and community aggregation load.
The purpose of the workshop, as reflected in the Ruling, is not to "re-invent the wheel." In developing their procurement plans, the utilities have explicitly engaged in resource adequacy by assessing the availability of resources to meet their expected demand. Additionally, many of the same parties involved in this proceeding have already participated in the CPA's Reserve Rulemaking, the CEC's Integrated Energy Policy Report (IEPR) process, and the Resource Adequacy Working Group (RAWG) process run by the Inter-Agency Working Group56 on behalf of the ISO. Although these efforts may not have resulted in parties reaching consensus, they have resulted in framing many of the questions that need to be addressed, and the options available for addressing them.
To the extent possible, the workshop also should develop a common approach, or "template" as WPTF calls it, for evaluating each LSE's resource adequacy. While complete consistency between all LSEs' may not be feasible, at a minimum the workshop process should result in common approaches so that decision-makers and interested parties can evaluate and compare resource adequacy both between utilities and between all entities under Commission jurisdiction. Finally, the workshop should ensure that Commission policy preferences on resource loading order are fairly and accurately counted toward the resource adequacy goal.
We now address the specific areas that the workshop is to address.
First, the workshop will provide a forum for parties to better understand, and for the utilities to explain, how their load forecasts are performed and opportunities to improve consistency between the utilities. As we discussed elsewhere, the utilities should retain the primary responsibility for developing their forecasts. As SCE states, although parties have complained about the lack of consistency of the forecasts, no party has substantively challenged the results of its forecast. As SDG&E states:
"As a general matter, SDG&E previously explained that there is an unnecessary preoccupation with `common' or `perfect' assumptions to be used by the utility in its long-term resource planning. In SDG&E's view, while assumptions clearly need to be reasonable, the more critical piece is the testing of the assumptions to accommodate uncertainty). In the end, the utilities must plan using the best data for their unique circumstances, as they are accountable for the results."57
In the workshop it will be necessary to identify the treatment of direct access load and who should be responsible for forecasting it.
With regard to supply resources the primary focus of the workshop should be the "counting" of resources available to meet demand. How resources are counted in large part depends upon the type of resources that are considered.
The treatment of Utility-Retained Generation (URG) appears fairly straightforward, as almost all parties believe it should be based upon some variant of "dependable capacity," although there is no consensus on how to calculate it. A review of the utilities' filing tends to confirm that they have already accounted for, to a large extent, the availability of their URG resources in developing their procurement plan. How the utilities should value their retained generation should be one of the focuses of the workshop.
The treatment of existing and future contracts and how they should be valued in a resource adequacy framework should be another area of focus for the workshop. As previously mentioned, this includes full recognition of the long-term DWR contracts; the criteria under which other contracts should be counted; and, as ARM suggests, "the treatment of ESP firm energy contracts."58
Another issue for the workshop, and consistent with the Joint Recommendation, is the criteria to be used for the reliance of the utilities upon the spot capacity and energy markets to meet a portion of their energy needs. As previously mentioned, we want to ensure that to the extent the utilities rely upon this capacity that we can be reasonably sure that this capacity will be available even under adverse conditions.
Finally, the workshop should address how the preferred energy resources that the Commission is planning to rely on to meet its energy needs can be fully valued under a resource adequacy framework. These so-called "soft" resources (i.e., energy efficiency, renewables, demand response) can provide a significant and cost-effective means to reduce capacity needs yet they have proven exceedingly difficult to count towards resource adequacy requirements under the traditional resource adequacy frameworks such as the ISO-run capacity markets in the Eastern United States.
The Joint Recommendation proposes to include these resources in each utilities' resource adequacy framework, proposing that each utilities' peak load requirements, for both planning and operating reserves, be:
"reduced to reflect: 1) Energy Efficiency programs with authorized and funded program designs; 2) Additional Energy Efficiency Programs proposed by the IOUs in their resource plans (and approved by the Commission) based upon potential savings estimates; and 3) existing and future Interruptible or Non-Firm Load Programs."
And that:
"Demand Response Programs consistent with the levels adopted by the Commission in D.03-06-032 should be included in the IOU load forecasts or resource plans."59
The Joint Recommendation goes on to propose that methodologies be developed to reflect the value that these programs have in reducing peak demand requirements.60
In conducting the workshops and developing a resource adequacy framework, the Commission reiterates its commitment that full value be given to the preferred resources identified in the Energy Action Plan and to 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 and 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. Not counting these type of "soft" resources in the traditional resource adequacy frameworks could result in California having to pay twice for capacity thus limiting the cost-effectiveness of these programs. Collectively, for example, the three utilities are planning to achieve over 1,200 MW of peak load reduction from energy efficiency programs.
Counting these resources towards any resource adequacy framework is also consistent with previous Commission decisions. D.02-10-062 requires that "utilities include in their plans procurement of base-load and intermediate load reductions in the form of energy efficiency"61 while
D.03-06-032 in the Advanced Metering OIR requires the utilities to "include the MW targets for calendar year 2003-2007 in their procurement plans to be filed in R.01-10-024."62
The ability to count these resources, under reasonable and realistic parameters, should therefore be addressed in the workshop. In addressing this issue, parties should focus on how the results of other Commission proceedings can be coordinated with the procurement proceeding so that the Commission (and other parties) do not end up evaluating the same programs twice. For example, the Commission, in R.01-08-028 is already examining the effectiveness of the utilities' energy efficiency expenditures.
Issues of deliverability of resources and penalties will also be addressed in the workshop.
Finally, as noted in the Assigned Commissioner/ALJ Ruling:
"[I]t is premature to address reporting requirements at this time. It is difficult to determine reporting requirements when it is still unclear what exactly it is that is to be reported...Based on the policy guidance given by the Commission in its year-end decision, the results of the workshop and the success of parties in reaching agreement, the Commission will be in a better position to address the issue of how the information will be used. This subject may be appropriate for a follow-on workshop."
The scope and schedule for the workshops will be the subject of a ruling from the Assigned Commissioner or ALJ within 15 days of this decision.
9. Deliverability
In general, the utilities in their filings sought to address the issue of ensuring that the generating resources upon which they plan to rely are deliverable to their systems. As SCE notes, the simulation models it uses 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. As the utilities resource choices become more focused (e.g., selecting a specific plant or transmission path to access a resource), the utilities should provide greater specificity in their showings that such resources are deliverable to loads, including the effect of adverse conditions upon such delivery.
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."
SDG&E's definition is a useful starting point to address deliverability requirements for larger resources.
We are aware of FERC's most recent pricing policy requiring transmission owners to provide a credit to generators for network upgrade costs,63 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 rights.64 This is one definition of deliverability for new resources that will be discussed further at the workshops.
We remain concerned that for smaller energy sources that are either located close to load centers, such as distributed generation, or that displace load, such as a broad scale energy efficiency or demand response programs, appropriate deliverability requirements can be developed that will not impose excessive or unreasonable regulatory burdens that deter their use and deployment.
The issue of deliverability is an issue that clearly needs further study and should be addressed in further detail in the utilities' revised long-term plans. Therefore, following the workshop process, we may seek additional comments in the next procurement rulemaking as to how to assess and develop workable deliverability standards.
B. 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.65 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 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 was evaluated and approved with modifications in D.03-12-059. 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 non-utility 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. One approach includes a competitive solicitation to 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 may face challenges when trying to construct new plant as it has been twenty to thirty years since they built fossil-fuel plants. Therefore, the solicitations may request turn-key plants and PPAs with later purchase options rather than initial utility construction.
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 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 a wide set of choices for development.
We do acknowledge, however, that the utilities are free to present to us at any time applications for certificates of public convenience and necessity (CPCN) for generation projects that are utility-owned and/or utility-built. By requiring RFPs as a standard procedure for non-utility owned generation resources, we are by no means discouraging utility projects where they are cost-effective and appropriate. However, the Commission does not have a comprehensive methodology available at this time to evaluate such projects against alternatives brought to us through a competitive RFP. Thus, we will consider utility-owned and/or utility-built proposals on a case-by-case basis. Utilities proposing a CPCN should, at the time of application, present evidence and justification for why the utility ownership structure is preferable and how cost containment should be addressed.
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. 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.
WPTF further points out, in its comments on the alternate decision, that generation plant owners may also conduct RFPs, and that it may be beneficial to have the utilities participate in those solicitations. Thus, in response to WPTF's comments on this issue, we grant that additional authority. In particular, we wish to clarify that the utilities are permitted to bid in open seasons or RFPs held by generation owners. The applicable terms of the contracts being offered in the generator RFPs or open seasons need not match precisely the utility authority to conduct their own RFPs. However, the terms should be reasonably similar. To encourage reasonable bidding practices, we encourage the utilities to consult with their PRGs in advance of submitting any bids in generator RFPs or open seasons.
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 will be 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. We also agree with the City of Chula Vista, which encouraged the Commission to have the utilities fill many of their immediate resource needs with shorter-duration contracts so as to avoid potential stranded costs for Community Choice Aggregation, and we expect the utilities to shape their portfolios accordingly.
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 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.
PG&E, in particular, raises concerns in its comments about its ability to buy firm system sales, which come with strong financial protection, as well as its ability to do hydroelectric exchanges and purchases with the Pacific Northwest. The Commission does not want to foreclose seasonal exchanges that benefit the ratepayers or PG&E's ability to tap cheap hydroelectric resources in the Pacific Northwest. As such, the Commission declines to limit utility purchases of non-unit contingent types of contracts. However, we are opposed to utilities' signing any additional non-unit contingent contracts that do not specify delivery point (e.g., the DWR contract with Sempra). Such contracts are not beneficial to providing California with reliable electricity and make more difficult the jobs of the utility dispatching the contract and the ISO dispatching its entire control area. While we would not expect a utility to propose to sign such a contract in the future, we wish to make clear that we will not allow such contracts prospectively.
It is clear from this beginning discussion that considerable additional work and evidentiary record development is needed for the Commission to establish workable and reasonable parameters for portfolio mixes most beneficial for the next five years. The next phase of this procurement effort will address these issues prior to the Commission's approval of a long-term procurement plan for any utility.
6. Affiliate Transactions
a) Existing Moratorium and Standard of Behavior 1
In hearings held in 2002, 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.66 (D.02-10-062, p. 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) The 2003 Hearing Record
In hearings held during 2003, 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 pre-approval 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.67 However, we will grandfather already existing contractual relationships with affiliates (e.g., QF contracts) for the life of the existing plant in order to ensure that existing resources with such relationships can continue to serve California. 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. 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 non-affiliates 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. We may review this finding after completion of the SDG&E/SoCalGas/SEU audit, as discussed below.
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:68 69
"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.70 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, pp. 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.
3. Grandfathering of already existing contractual relationships with affiliates (e.g., QF contracts) for the life of the plant.
C. 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/noncore 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 S&P, Moody's and Fitch. On December 18, 2003, PG&E and the Commission reached a Modified Settlement Agreement (MSA) which according to PG&E, "paves the way for the utility to emerge from Chapter 11 as an investment grade company...."71 On December 19, S&P indicated that it would place PG&E's current "D" grade72 credit rating on its CreditWatch listing, "with positive implications."73 On December 23, Moody's upgraded PG&E's rating to Ba2, two notches below investment-grade. Bolstered by these recent developments, and with financial metrics improved, 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 their next plan filing. We agree with the utilities and other interested 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.
SCE and SDG&E now have investment-grade credit ratings, and PG&E expects to return to investment-grade status soon. 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 maintaining commercial viability. SCE and PG&E provided most of the testimony on debt equivalency, credit capacity and collateral issues. 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 at least some 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, in assessing an entity's debt-equity ratio. Credit analysts may adjust a utility's balance sheet and income statement entries by assigning a debt equivalence amount (in dollars), expressed as the net present value of a PPA's capacity payments, multiplied by a "risk factor." The risk factor can be 0% to 100% of these contractual payments, depending on the type of obligation. The adjusted financial information is used to calculate the financial measures that are part of assessing a utility's credit quality.
a) SCE's Concerns for Long-Term Power Contracts
SCE has now received investment-grade credit ratings from all three rating agencies. SCE asks that the Commission take steps to maintain the utility's creditworthiness and financial viability. SCE states that being creditworthy 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."74 Credit ratings upgrades often occur due to improvements in general economic, industry, or company-specific conditions, rather than to a single issue deliberated by the Commission.
For example, we look at the Commission's recent decision of December 18, 2003, approving the MSA which underpins PG&E's plan for emergence from bankruptcy. On December 23, 2003, Moody's upgraded PG&E's credit rating three notches, from B2 to Ba2. Two factors seem to have influenced the upgrade: (1) the settlement allows PG&E a timely exit from bankruptcy; and (2) the company had a strong pre-settlement cash position (as of 10/31/200), equivalent to $4.1 billion.75
S&P is reviewing PG&E's credit rating, citing three factors which would influence their determination: (1) the assessment of the MSA and its financial implications for PG&E; (2) the utility's ability to support expenses of its parent company; and (3) debt equivalency related to current and expected long-term contracts.
c) Commission Procurement Policy and Treatment of Debt Equivalency
Preliminarily, we note that AB57 (as per Public Utilities Code Section 454.5(a)(b)(1)) requires "an assessment of the price risk associated with the electrical corporation's portfolio, including any utility-retained generation, existing power purchase and exchange contracts, and proposed contracts or purchases." Thus we take the emerging issue of debt equivalency, and its potential impact on the utilities' financial viability to serve its customers, quite seriously.
We also note that the debt equivalency issue has gained prominence recently, and we wish to examine its impact on utilities carefully. It appears that the three rating agencies have varying methodologies for assessing debt equivalency and there is some subjectivity in this process which is not transparent, adding to the difficulty of this assessment by the Commission. In addition, we note that debt equivalency is only one of the many factors affecting a utility's credit rating and therefore its cost of borrowing.
Nonetheless, SCE's concern with this issue is warranted, and we intend to examine it carefully. However, this proceeding is primarily concerned with setting overall policy for resource procurement, and not addressing capital costs for utility investments owing to debt-equity ratios or credit ratings. The more appropriate venue for handling the potential costs associated with additional debt equivalency attributed to a utility for its PPAs is in each utility's cost of capital proceeding. (See D.92-11-049 and D.93-12-022). Therefore, the utilities should present detailed evidence about the treatment of debt equivalency by the rating agencies in their upcoming cost of capital filings. The Commission will consider these issues therein and develop a more robust evidentiary record on this subject before reaching a conclusion based on each utility's unique financial situation.
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 was 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. With SCE's return to investment-grade status and PG&E's recent Modified Settlement Agreement (MSA) approved by the Commission, we find no financial barrier which would preclude long-term procurement.
SCE asks that the Commission take steps to 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 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. We expect PG&E and SCE to revise their collateral estimates (if needed) to reflect changes in its financial capacity now enabled by the MSA and the return to investment-grade status, respectively.
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 decision-making. The Commission's policy for assessing the utilities' financial capabilities may consider issues which affect capital structure in tandem with those affecting immediate cash needs. Moreover, we note that there are elements of credit risk related to collateral issues which transcend cash requirements. Addressing these issues in a single proceeding will better ensure that cohesive policy measures are established.
Finally, we note the positive reaction from credit rating agencies (credit upgrade) to the MSA, which enables PG&E to exit from bankruptcy. 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. SCE has recently regained its investment grade credit ratings. PG&E will soon emerge from bankruptcy, and it expects to regain its investment-grade rating shortly. One possible solution is to focus on transacting with investment grade counterparties, without collateral support. 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 as 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.
16 In its recently adopted Integrated Energy Policy Report (adopted November 12, 2003). 17 A significant portion of the municipal load within the ISO is served by municipal utilities which have chosen to become Metered Subsystems (MSS) under the ISO's tariffs (ISO Amendment 46, approved by FERC [100 FERC ¶ 61,234 (2002) (August 30 Order)]. 18 TURN, Exh. 81, p. 18-19. 19 FURTHER ORDER ON THE CALIFORNIA COMPREHENSIVE MARKET REDESIGN PROPOSAL (Issued October 28, 2003 in Dockets ER02-1656-003, ER02-1656-004, ER02-1656-015 and EL01-68-028), footnote 98 to para. 215. 20 Exh. 68 prepared by Mr. Lauckhart at the request of ALJ Walwyn. 21 It should be noted that the ISO Forecast does not include recent actions taken by the Commission to improve the supply situation such as the 1,054 MW Mountainview project (D.03-12-059); increase energy efficiency funding totaling 950 MW over five years (D.03-12-062); or SDG&E's recently proposed 500 MW Palomar facility which the Commission will consider soon. The ISO's forecast also does not include the 1,100 MW of the existing interruptible program.
"Governmental entities have long planned their systems to ensure resource adequacy. In fact, during the advent of competition, while other entities were moving away from the concept of long-range resource planning, government entities were continuing to plan their systems to ensure that they had sufficient resources to satisfy their future load."
22 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."
23 The Joint Recommendation proposes that the terms "Dependable Capacity," "Peak Load" and "Reasonably Expected Resource Outage" should be defined as part of a permanent resource adequacy framework to be developed. (See Section I.8 of this Joint Recommendation.) 24 The Joint Recommendation was submitted by SCE, PG&E, SDG&E, TURN, ORA and the CEC.25 MR. PETTINGILL: Well, that's part of what goes into the assessment when they start with the baseline of 1 day in 10 years. Then they look at the historical outage rates of the different technology units, the size of those units, and then determine what's an appropriate reserve margin to meet that one day in 10 years.
COMMISSIONER WOOD: Has Cal ISO conducted that type of analysis in arriving at a recommendation of 17 percent for our utilities?
MR. PETTINGILL: We have not done the analysis. (Tr. 5991-5993.)
- "Requires electric service providers to comply with conditions, including resource adequacy standards, that the commission determines to be necessary and appropriate to ensure there is no adverse effect on the reliability or cost of electricity for core customers." (Proposed Pub. Util. Code § 365(h).).
- "it is the intent of the legislature to affirm the electrical corporation's obligation to provide transmission, distribution, and resource adequacy services for all customers."
60 "The accounting for all Energy Efficiency programs to meet capacity and reserve requirements shall be subject to corrective feedback from measurement and evaluation of actual impacts compared to expected impacts..." (Joint Recommendation, I.6.)
61 D.02-10-062, p. 27. 62 D.03-06-032, Ordering Paragraph 1c. 63 Network upgrades represent reliability or deliverability upgrades to the transmission system beyond the first point of interconnection that would not have been necessary "but for" a particular generator interconnection. 64 FERC 104 FERC 61,103 Dated July 24, 2003 see paragraphs 754- 756, 767-768. 784 for FERC discussion regarding deliverability of capacity resources, See paragraph 695 for FERC discussion regarding compensation for network upgrades in ISOs and RTOs with Locational Marginal Pricing. 65 Department of Energy/EIA - 0348 (01) 2 State Electricity Profiles 2001, p. 19, published October 2003. 66 The moratorium did not preclude "transactions through the ISO that can be demonstrated to include multiple and anonymous bidders". (See FF21.) 67 SDG&E has a pending motion before us to consider a transaction with a Sempra affiliate, Palomar Energy. That matter has been separately set for hearing and is not addressed here. 68 D.02-10-062, placed a moratorium on SCE, PG&E and SDG&E dealing with their own affiliates in procurement transactions, beginning January 1, 2003, lasting for two years or until the rulemaking is completed, whichever date is first. (See p. 50, mimeo.) 69 D.03-06-067, "Gas Procurement for the utilities' DWR is a hybrid: it should follow the same standards as gas procurement for the utilities' own contracts, yet it is reviewed under a separate Gas Supply Plan, with the review conducted annually in conjunction with DWR contract administration and least-cost dispatch." (See p. 10, mimeo.) 70 In some instances PG&E's tariff allows the utility to negotiate prices with their customers for certain services (e.g., parking and lending). 71 PG&E News Release, December 18, 2003. 72 Current rating is three notches below investment-grade. 73 CreditWatch, December 19, 2003. 74 ORA OB, p. 9. 75 Moody's Global Credit Research: Opinion Update, December 28, 2003.
