3. Discussion
The urgency of addressing reliability for Summer 2004 required a shortened period for parties to respond to the ACR. Parties responded quickly with thoughtful and constructive comments and replies. We appreciate their focused work on an expedited schedule.
This order addresses a specific problem associated with stressed CAISO real-time operations stemming from a lack of deliverable resources in the SP 15 zone. This arises from what appears to be SCE's over-reliance on resources that are not deliverable to load in the SP 15 area. When resources are scheduled and procured without regard to their actual deliverability to load or the total cost of procurement (including CAISO re-dispatch costs), the CAISO is forced to line up additional resources to assure that load is served in real-time. For instance, we understand that the majority of must-offer calls occur in SP 15. Large volumes of non-deliverable resources requiring real-time re-dispatch results in operational challenges and risks to system reliability. The extent to which utilities schedule and procure resources pursuant solely to a least direct cost criterion, ignoring the CAISO re-dispatch costs and reliability implications, can aggravate real-time management of congestion and pose challenges for system reliability.
Reliability-Must-Run (RMR) contracts are contracts the CAISO enters into to assure that units required for local reliability are available. Relatively few RMR units are under contract in the SP 15 area, particularly in SCE's service territory. This is in contrast to other service areas in Northern California and elsewhere (e.g., PG&E and SDG&E). Moreover, the majority of must-offer calls occur in the SP 15 area. These circumstances reflect a relative disconnection between the resources that are scheduled and the ones that are required to serve load in the SP 15 area. The specific situation whereby the CAISO has to re-dispatch the system to make up for non-deliverable resources scheduled or procured by utilities must be addressed, and addressed now, since it affects reliability for summer 2004.
The long-term solutions to these problems will be found in market design changes and the resolution and implementation of resource adequacy issues in this ongoing docket. For this reason, we intend the guidelines outlined in this order to serve as a "bridge" until these longer term issues are fully litigated and resolved. Our goal is to see incremental improvement, not perfection, in addressing the outstanding operational problems highlighted in the CAISO's letter. Therefore, this order will remain in effect through the earlier of year-end 2005 or the issuance of a superseding order or orders addressing these issues in this proceeding.
This order is initiated to clarify past Commission orders to address specific operating and reliability problems associated with scheduling and procurement practices in a specific area in Southern California. At the same time, however, the principals embodied here are broadly applicable. That is, we want the CAISO to have the best reasonable opportunity to do its job, and to address problems as they arise. To do so, utilities must take congestion and reliability considerations into account (to the extent they are reasonably able to do so) when making immediate, short-term, intermediate-term and long-term scheduling and procurement decisions.
Thus, we rely on the CAISO to take all reasonable steps to enable market participants to increase reliability by scheduling and procuring resources in a manner that minimizes CAISO operational problems while letting CAISO fulfill its fundamental mission of ensuring reliable grid operation. The Commission strongly encourages the CAISO to take steps to provide all Load Serving Entities with the information they require to procure and schedule resources in a manner that supports reliable grid operations. Anything short of the ISO's best efforts in this regard will only serve to perpetuate operational issues and reduce the effectiveness of the efforts the Commission makes in this order.
3.1. CAISO and Utility Roles in Assuring Reliability
The Commission and the Legislature have expressed their clear intent that utilities should procure resources in a manner consistent with utilities' statutory obligation to serve their customers. The utilities' obligation to serve customers is mandated by state law and is a fundamental element of the entire regulatory scheme under which the Commission regulates utilities pursuant to the Public Utilities Act. (See, e.g., §§ 451, 761, 762, 768, 770.) While § 345 clearly assigns the CAISO responsibility for ensuring reliable grid operations, this statutory obligation does not diminish in any respect the utilities' obligation to procure resources for their loads to ensure reliability. To be clear, it is our view that while the CAISO has the responsibility to ensure and maintain reliable grid operations, it is the LSEs responsibility to have sufficient and appropriate resources to make that reasonably possible.
The CAISO has the authority, experience, knowledge, tools, process and ability to fulfill its responsibility to assure reliable grid operations.2 Procurement, however, is not part of CAISO's core functions. The CAISO's ability to operate the system in a reliable fashion is contingent upon utilities fulfilling their responsibility to have sufficient resources to meet load (not just system wide but also locally), and to schedule resources in a manner reasonably consistent with reliable grid operations. As discussed further below, we recognize that the CAISO has the authority to procure resources (e.g., RMR contracts, other types of contracts, must-offer provisions of the CAISO tariff). It is our position, however, that these CAISO tools should not be used to supplant the utility's obligation to procure resources to meet its customer's needs. Rather, the CAISO procurement authority should be a backstop reliability tool.
3.1.1. Incremental Improvement
We first note that it seems many parties read the ACR as a more radical proposal than we think was intended. We do not understand the proposal to, and we do not adopt a policy here, that "abruptly change[s] the regulatory/legal framework for grid reliability that has now existed for 6 years..." (SCE Comments, page 5.) Nor do we adopt "an abrupt about-face from policies that this Commission established only recently in D.04-01-050." (TURN Comments, page 3.)
What we do is to "help the ISO maintain reliability by providing the utilities additional flexibility in their dispatching decisions..." (PG&E Comments, page 3.) We "remove a perceived disincentive to [utilities] scheduling resources in a manner more consistent with the CAISO's operating requirements." (CAISO Reply Comments, page 9.) We also facilitate "incremental improvement in IOU [investor owned utility] scheduling practices..." (CAISO Reply Comments, pp. 3-4.)
The Commission has unambiguously established procurement guidelines recognizing both reliability and least cost objectives while noting the objectives are interrelated and that reliability comes with a cost. For example:
"In making plans to procure a mixture of resources, the utilities should take into account the Commission's longstanding procurement policy priorities - reliability, least cost, and environmental sensitivity. While each of these priorities is important individually, they are also strongly interrelated. Increased reliability may increase procurement costs." (D.02-10-062, mimeo., pp. 17-18.)
The Commission has emphasized the importance of taking reliability into account:
"We direct the utilities to include a local reliability component in their next procurement plan. This approach will facilitate a more comprehensive approach to resource planning. It is our intent that this approach will increase the effectiveness of resource procurement and result in lower costs to ratepayers." (D.04-01-050, mimeo., p. 129.)
Accordingly, a utility scheduling practice or procurement plan that focuses solely on least cost energy, without regard to deliverability of the procured energy to load or to local reliability, is not in compliance with our prior decisions, approved short-term procurement plans, and Assembly Bill (AB) 57.3 SCE in its comments on the draft decision asserts that the Commission is changing a previously approved short-term procurement plan in today's decision. (SCE Comments, pp. 9-10.) This argument misstates the point: this Commission has never required an exclusively least cost focus in its oversight of the IOUs procurement plans, as the preceding citations demonstrate. Furthermore, while SCE states that its focus has been on least cost, we merely provide further guidance in this decision as to what that "least cost" analysis should consider, i.e., the total cost of the IOUs scheduling and procurement practices, including ISO-related costs.
We underscore those principles by emphasizing that utilities should not limit their assessment to least cost day-ahead scheduling and procurement practices but must incorporate all CAISO-related forward commitment costs that result from the utilities' scheduling and procurement decisions. These costs should include all known or reasonably anticipated CAISO-related costs including congestion, re-dispatch, and must-offer costs.
We have always directed, and continue to direct, that utilities act reasonably and responsibly. We emphasize that, as we have directed in prior decisions, reasonable action is not to pursue "least cost" by minimizing only short-term cash flow expenditures.
Rather, each utility has a duty to provide safe and reliable electricity at a reasonable cost. Reasonable cost means least cost taking into account all relevant factors, such as short run, the long run, cash flow, total cost, safety, reliability and environmental sensitivity. Minimizing total cost, and taking reliability into account, means incorporating all known and reasonably anticipated CAISO-related costs (including congestion, re-dispatch costs and must-offer costs) when evaluating scheduling and procurement options.
In its comments, SCE proposes an alternative means to meet the objectives outlined in the ACR. SCE proposes that the CAISO test the feasibility of adjusting day-ahead schedules to determine whether the schedules would require re-dispatch. The CAISO responds that its existing software does not indicate how to adjust day-ahead schedules in the most effective and least cost way. The CAISO states that it is evaluating interim approaches to manage congestion until Market Design 2002 (MD02) is implemented, but these approaches would not be ready in time to ease operational problems for summer 2004.
SCE's proposal, even if meritorious, does not appear feasible for summer 2004. Therefore, we maintain that improvement to scheduling and procurement practices is an immediate means to address existing operational problems. We encourage SCE to work with CAISO on long-term remedies to improve market design and operation.
Our decision here does not mean that a utility should be cavalier in incurring reliability costs on behalf of persons or entities that are not its customers (e.g., LSEs, energy service providers (ESPs), municipal utilities) and expect to charge those costs to its ratepayers. At the same time, it means performing a reasonable balance taking into account requests and information provided by the CAISO in this relatively new, complex, hybrid market.
Many parties have raised the issue that the available information for rational decision-making is limited.4 For example, utilities argue that the FERC prohibits utility power procurement employees from having access to information from their own company's transmission departments. These restrictions make it impossible for utility employees engaged in procurement to confer with their transmission colleagues who might be better able to "discern" or "reasonably anticipate" reliability issues and CAISO costs. TURN is concerned that, absent specific and accurate information, utility procurement departments "may `guess wrong' and actually make the situation worse that it was to begin with." (TURN Comments, page 4.)
We seek reasonable, incremental improvements that benefit California. The CAISO is in the process of developing additional information that it may release to all market participants regarding congestion and local reliability constraints. We expect each utility to use whatever information it may
lawfully obtain, and that the CAISO may lawfully disseminate (without increasing the market power of any seller), to improve upon the current situation.5
3.1.2. Reliance on RMR Contracts
SDG&E, PG&E, and others note that the operational and reliability problems the CAISO faces are occurring predominantly in SP 15. Specifically, local reliability issues are being addressed in PG&E's and SDG&E's service territories by RMR contracts. By comparison, SCE's service area has few RMR contracts. TURN, SCE and others maintain that it is the CAISO's responsibility to ensure local reliability by way of RMR contracts, and that the CAISO should do so in SCE's area.
We have been clear, however, that it is our intention to minimize the use of RMR contracts, and that the utilities should include local reliability in their long-term procurement plans for the purpose of reducing the need for RMR contracts. For example, we said:
"They [RMR units] are predominantly in transmission-constrained areas where local generation near load balances the limitation on imports over constrained transmission lines. While RMR serves an important purpose, RMR contracts are annual contracts that detract from a comprehensive infrastructure planning approach. They are also expensive, costing $360 million in 2003. ... The IOUs in their long-term procurement plans are in a position to foster a more comprehensive approach to meeting local and system needs through long range plans that incorporate generation, transmission, and demand-side trade-off analysis from a least cost perspective. We direct the utilities to include a local reliability component in their next procurement plan. This approach will facilitate a more comprehensive approach to resource planning. It is our intent that this approach will increase the effectiveness of resource procurement and result in lower costs to ratepayers." (D.04-01-050, mimeo. pp. 128-129).
The recent Assigned Commissioner's Ruling and Scoping Memo regarding the long-term procurement plans further reinforces the intention to address local resource adequacy and deliverability (e.g., load pockets) by stating:
"Finally, assume that in addition to a general service area-wide requirement, LSEs must satisfy a resource adequacy requirement for any load pockets in their service areas. In preparing and documenting both the input assumptions (e.g., definition of load pockets, load forecasts for such load pockets, resources tabulated by load pocket, etc.) and results (e.g., additional resources required, costs of these additional resources, reduction in RMR costs, etc.) of these two alternative possibilities for the deliverability issue, the differences between these two variants of each Resource Plan should be thoroughly explained." (Ruling dated June 4, 2004, Attachment A, page 9.)
Our position is that the utilities are responsible for procuring the resources to meet their customers' needs, including local needs. Although we expect that RMR contracts will remain available as, at a minimum, a backstop mechanism to mitigate local market power in the future, RMR contracts are relatively expensive, especially considering their limited operating parameters. Moreover, they fragment a more comprehensive planning approach from the perspectives both of transmission and overall procurement.
Furthermore, an approach that subsumes local reliability contracts within the scope of utilities' long-term plans is a proactive approach. It reduces vulnerability to price increases and volatility as FERC evolves its pricing and market design policies pertaining to RMR contracts and reliability within load pockets. Indeed, FERC's most recent rulings on the treatment of RMR contracts in connection with the New England Regional Transmission Organization and the Pennsylvania-New Jersey-Maryland Interconnection cast doubt on the long term viability of RMR contracts to serve the goals of local market power mitigation and local reliability. 6 Given FERC's recent actions with regard to reliability compensation issues and its clear preference for market-based solutions in lieu of RMR contracts in the Eastern ISOs, as well as the relatively expensive and inefficient nature of the existing RMR contracts in California, it is our intention and desire to minimize the use of RMR contracts through IOU scheduling, procurement and comprehensive planning. The Commission believes that consumers are better served from both a cost and a reliability perspective through a proactive planning, procurement and scheduling approach.
In summary, while the Commission understands that some limited (and cost efficient) continuation of RMR contracts may be necessary as a backstop mechanism in the future, a policy that encourages the CAISO to assume greater procurement responsibility in connection with local area reliability would be shortsighted. Moreover, consumers would be ill served by such a short-sighted policy. Therefore, we encourage a comprehensive planning approach via IOU scheduling and procurement to minimize the need for RMR contracts. This policy will facilitate better overall resource planning and reduce the potential vulnerability to price and market design changes that could dramatically increase the cost of RMR contracts in the future.
3.1.3. Modify Restriction on Use of Bilateral Negotiated Contracts
D.03-12-062 addressed the appropriateness of utilities' use of bilateral negotiated transactions, and limited their use to specific circumstances.7 The decision's list of authorized transactional processes quoted previous decisions that expressed a similar concern and provided authorization only in particular limited circumstances.8 The decision noted proposals of PG&E and SCE to expand the circumstances under which bilateral negotiated transactions are authorized. Ultimately, D.03-12-062 limited authorization to three circumstances:
"First, for short-term transactions of less than 90 days duration and less than 90 days forward, the IOUs are authorized to continue to use negotiated bilaterals subject to the strong showing standard we adopted in D.02-10-062, as modified by D.03-06-067. Any such negotiated bilateral transactions shall be separately reported in the utilities quarterly compliance filings.
"Second, utilities may use negotiated bilateral contracts to purchase longer term non-standard products provided they include a statement in quarterly compliance filings to justify the need for a non-standard product in each case. The justification must state why a standard product that could have been purchased through a more open and transparent process was not in the best interest of ratepayers.
"Last, we expand the authorization for use of negotiated bilaterals for standard products in instances where there are five or fewer counterparties who can supply the product, as suggested by SCE. We limit this authority, however, only to the two categories of gas products cited by SCE: gas storage and pipeline capacity. In such instances, the utility needs to affirm that five or fewer counterparties in the relevant market offered the needed product. Any resulting contract shall be separately reported in the utilities' quarterly compliance filings." (D.03-12-062, mimeo. pp. 39-40.)
The decision concluded that "Negotiated bilateral transactions should be separately reported in the utilities' quarterly compliance filings." (D.02-12-062, mimeo. p. 84, Conclusion of Law 11.) It also concluded that there should be limited use: "Where there are five or fewer counterparties in the relevant market, we should authorize the use of negotiated bilaterals for standard products for two categories of gas products cited by SCE: gas storage and pipeline capacity." (D.03-12-062, mimeo. p. 84, Conclusion of Law 15.)
Today we relax the restrictions on negotiated bilateral contracts so that the utilities may take appropriate actions to reduce overall costs and increase local area reliability. In addition to the limited circumstances enumerated in D.03-12-062 at Conclusion of Law 15, we authorize the utilities to engage in bilateral negotiated contracts for capacity and energy from power plants where the purpose is to enhance local area reliability.9 Utilities may include such transactions in their quarterly compliance filings, for approval if there is no objection.
3.1.4. Spot Market Transactions Limitation Relaxed
D.03-12-062 continued a guideline (previously stated in D.02-10-062) that the utilities should plan their market exposure and justify spot market activities that exceed 5% of monthly needs. The decision further explained that:
"this guideline applies to energy procurement in Day-Ahead, Hour-Ahead, and Real-Time markets and it is intended to represent a target amount, rather than a hard limit, as there may be economic reasons justifying a utility's decision to exceed the target (i.e., least-cost dispatch). We also find that this guideline provides an appropriate balance between procurement flexibility and reliability." (D.03-12-062, mimeo. page 10.)
Finding of Fact 4 states the point precisely:
"The 5% of monthly need target on spot market purchases from D.02-10-062 provides a balance between procurement flexibility and reliability and it is reasonable to continue to require the utilities to justify a higher level." (D.03-12-062, mimeo. p. 81.)
We note that this is a guideline, not a strict limitation. We also provide additional clarification. To the extent that utilities see the need to engage in spot-market transactions to enhance local area reliability, whether on their own accord or in response to information provided by the CAISO, they should do so whether or not those transactions will raise the total percentage above 5% of the total monthly need. The utilities should not be restricted by this general guideline from taking actions that enhance local area reliability and reduce overall costs. Of course the utilities may include in their quarterly compliance filings any transactions above the 5% guideline, for approval if there is no objection.
Despite this clarification, however, we continue to emphasize the benefits of avoiding over-reliance on spot-market transactions. That is, we take this action to ensure that utilities have sufficient flexibility to procure in a manner that recognizes deliverability of resources and reduces CAISO real-time operational challenges. This flexibility, should not be interpreted as encouragement to rely on spot markets rather than procuring sufficient capacity in the forward markets. Consistent with the Commission's goal of a robust resource adequacy requirement, our position remains that the vast majority of procurement practices should take place in the forward markets.
3.2. Application to Southern California and Statewide
PG&E and several parties contend that any solution to the problem identified by CAISO should be limited to the area in which the problem is occurring. CAISO, on the other hand, argues that the solution must be statewide. We conclude, as explained below, that the facts presented here relate to one specific geographic area and the policy solution is adopted with a focus on that area. The policy solution, however, applies equally in other areas wherein the same facts prevail, and generally apply statewide as described below.
We are concerned that a generalized policy solution adopted too quickly might cause unintended or harmful consequences. For example, TURN points out that requiring utilities in essentially all cases to change behavior and perhaps incur additional costs at the request of the CAISO for what might be a questionable need for added reliability:
"would create a dangerous disconnect between the party identifying the reliability needs and the parties responsible for the costs of meeting those needs. If these costs will show up `on the books' of the IOUs and not the ISO, there will be no inherent checks and balances in the process. The ISO will not have to weigh the potential for increased procurement costs against the sometimes marginal reliability benefits of a particular change in practice. This will create a powerful incentive for the ISO to over-prescribe reliability requirements in order to make life easier for the system operators, without any effective recourse by the people who pay the bills." (TURN Comments, page 5.)
We take this concern seriously. We do not intend to create a framework wherein CAISO reliability responsibilities are inadvertently shifted to utilities. Below, we outline a monitoring plan to assess the results of today's order.
CAISO argues that the policy must be statewide because congestion concerns are not limited to the SCE area. In support, CAISO says that approximately 32 areas of problematic congestion may exist on the grid in the near future, including areas in Northern California. We have no information on the facts behind the approximately 32 additional areas, however, and reach no conclusion based on this assertion.
Nonetheless, we directly apply today's decision to the area in Southern California wherein the problem has arisen. We also apply these principles to other areas with the same facts causing the same problems. In addition, we apply today's adopted policy statewide in that we require utilities to act reasonably and responsibly. That utility action, when evaluating resource options, includes minimizing total cost, taking reliability into account, and incorporating all known and reasonably anticipated CAISO-related costs (including congestion, re-dispatch and must-offer costs).
We also expect that neighboring utilities with DWR contacts in SCE's service territory will be scheduling and dispatching those resources in a manner consistent with today's decision.
3.3. Monitoring Plan
Comments have revealed a need to monitor the implementation of this order to assure that it has the desired effect on reducing CAISO real-time operations and associated CAISO-related costs. 10
We ask the CAISO to report back to the Commission within six months (or sooner if necessary) regarding the degree to which utility procurement and scheduling practices, particularly in the SP 15 area, are enabling the CAISO to meet its core mission of reliably operating the grid. We also ask the CAISO to report to the Commission the costs associated with its real-time re-dispatch. It is our belief that compliance with this order should result in reduced CAISO re-dispatch costs. That is, to the extent the utilities, particularly in SP 15, are scheduling and procuring resources in a manner that considers the deliverability of those resources and their congestion related costs, those practices should result in reduced must-offer, congestion, and re-dispatch related costs.
We further ask the ISO and SCE to meet and confer regarding outstanding information issues and provide a joint statement of resolution to the Energy Division. The Energy Division should reference the joint statement in a report to the Commission on the outcome on the efforts to resolve information-related issues. The Commission intends to use the Energy Division report to bring these issues into the record in R.04-04-003.
All of the utilities have raised the issue of market power of sellers. SCE emphasizes that loosening the existing restrictions on bilateral contracting does nothing to resolve the real problem of market power for sellers in the local area. The Commission will monitor market power issues and ask the CAISO and utilities to report to the Energy Division Director any instance of market power impacting the direction provided in this decision.
3.4. Cost Recovery
Utilities may recover costs incurred for reliability purposes consistent with this order. That is, actions taken in furtherance of the directives in this order are deemed consistent with the utilities' already approved short-term procurement plans and thereby subsumed within the protection provided by AB 57. This order, however, makes no modifications of any necessary showings already required of utilities as adopted by the Commission with respect to those procurement plans (e.g., strong standard showing in D.02-10-062, as modified by D.03-06-067; demonstration of reasonableness required in D.03-06-067).
Further, the ACR requested that commenters propose "cost-recovery mechanisms to appropriately recover reliability-related costs from non-IOU load serving entities, such as Direct Access providers and municipal utilities operating in the IOU service territory." Several parties commented on the difficulties that an allocation of reliability-related costs might occasion. (See, e.g., TURN at 3.) Other parties observed that the IOUs already have in place a mechanism by which they may recover reliability-related costs through their FERC-jurisdictional tariffs. (See, e.g., CMUA at 4-5; PG&E Reply at 4).
We expect IOUs to attempt to recover appropriately allocated reliability-related costs through their FERC Reliability Services tariff provisions.11 If utilities are denied recovery through this channel, utilities may seek cost recovery in the appropriate ERRA proceeding. We expect utilities to bring the matter to us with adequate time for reasonable consideration and decision.
Also, while AB 57 provides utilities with considerable cost recovery protection, we agree with TURN that this order is not to be understood as a "blank check." Rather, the efforts undertaken to procure in a reliable fashion are wholly consistent with the short-term plans approved by the Commission to date.
Finally, "the need for reasonable certainty of cost recovery" is a critical path issue to be decided by the end of 2004. (Scoping Memo dated June 4, 2004, page 4.) To the extent a utility addresses CAISO congestion or reliability concerns via its procurement plan, cost recovery is before us for decision by year-end, and we decline here to prejudge that outcome. At the same time, we repeat our basic criteria. Each utility has a duty to provide safe and reliable electricity at a reasonable cost. Reasonable cost means least cost taking into account all relevant factors (e.g., the short run, the long run, cash flow, total cost, safety, reliability, environmental sensitivity). Minimizing total cost, and taking reliability into account, means incorporating all known and reasonably anticipated ISO-related costs (including congestion, re-dispatch costs and must-offer costs) when evaluating short-term and long-term scheduling and procurement options.
