2. Background
2.1. Development of the PRM
With the restoration of investor-owned utility (IOU) procurement obligations in the early part of this decade, the Commission began to address the role of the PRM as a tool for ensuring cost-effective reliability in California's hybrid generation market.1 In October 2002, the Commission established that:
[T]he IOUs are responsible for procuring reserves on behalf of their customers' needs, as part of their continuing obligation to serve in order to ensure a stable, reliable power system. The ultimate goal is to safeguard the electric system by accounting for forced outages, operating reserves, and regulating reserves, as well as other contingencies.
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[I]t is important that the IOUs be responsible for procuring reserves to ensure system reliability. Historically, installed reserves have been 15-18% of system peak load. Therefore, on a provisional basis, we set the reserve level at 15%. (Decision (D.) 02-10-062, p. 29.)
Shortly thereafter, the Commission approved short-term procurement plans for 2003 for the three large IOUs. Finding the 7% operating reserves level proposed by the utilities to be adequate for 2003, the Commission then indicated its intention to further address the PRM based on a proposal by the Office of Ratepayer Advocates (ORA):2
For the long-term planning phase, ORA requests that each utility provide data sufficient to determine what level of planning reserves would lead to a loss of load probability [(LOLP)] of one day in ten years, as well as supporting testimony recommending a level of planning reserves. This is a reasonable request and, therefore, we adopt it. We note that ORA's request, while requiring specific data be furnished, allows each utility latitude to propose and support a planning reserve level it considers appropriate to its service territory. This should be done in conjunction with the provisional 15% reserve level and guidance we adopted in D.02-10-062. (D.02-12-074, pp. 30-31.)
The following year, in D.03-12-062, the Commission approved the IOUs' short-term procurement plans for 2004. IOUs were directed to procure sufficient resources to meet their peak demand plus an appropriate operating reserve margin of approximately 7% of peak demand as determined by the Western Electricity Coordinating Council (WECC). (D.03-12-062, p. 8.) The Commission made clear that it was adopting that approach for 2004 only while it developed long-term policy on appropriate reserve levels and the types of resources capable of meeting such reserve level obligations. (Id.) Responding to the concern of several parties that this was not sufficient, the Commission noted that the actual PRMs of the IOUs for 2004 were significantly above the 7% minimum operating reserves established for that year. (Id., p. 9.)
In January 2004, D.04-01-050 approved a long-term regulatory framework for procurement that included a PRM requirement applicable to all Commission-jurisdictional load-serving entities (LSEs), i.e., electric service providers and community choice aggregators as well as the IOUs. Although D.02-12-074 had suggested Commission interest in territory-specific PRMs that would lead to a LOLP of one day in ten years, pursuit of that interest was put on hold. The Commission established a statewide 15%-17% PRM, to be met by all LSEs by 2008.3 The Commission adopted this PRM level based on a determination that it would provide reliable service and an additional margin of safety. (D.04-01-050, p. 23.) In making this determination, the Commission referred to record information showing that a 15% PRM would produce a 2006 LOLP of 0.2 days in 10 years and "a `one day in fifty years' generation reliability criteria." (Id.) The Commission also stated concern that setting a higher PRM level, if implemented too quickly, could impact compliance with the preferred resource loading order of the Energy Action Plan. (Id., p. 24.)
2.2. Commission Implementation of and Commentary on the PRM
The Commission has taken several steps to implement its PRM policy in various RA and LTPP decisions. It has also had occasion to comment on various aspects of the PRM, including its value as a reliability planning tool and the components of its determination. These pronouncements are briefly recapped below.
Establishing counting rules for determining the qualifying capacity of resources under the RA program, the Commission found that:
An adjustment for forced outage rates is contrary to conventional practice in resource accounting, and the 15-17% PRM adopted in D.04-01-050 already includes assumptions about average forced outage rates. (D.04-10-035, Finding of Fact 10, p. 50.)
In another RA decision that addressed whether LSEs should be held responsible when a generating unit experiences a forced outage, the Commission found that:
Because the reserve margin adopted in D.04-01-050 encompasses forced outages, requiring LSEs to engage in replacement procurement following a forced outage would effectively require them to procure more than the adopted reserve margin. (D.06-07-031, Finding of Fact 2, p. 40.)
In a 2004 LTPP decision, the Commission rejected a proposal to develop demand forecasts for LTPP purposes by using a 1-in-10 peak weather standard. (D.04-12-048, p. 28.) In doing so, it noted that the RA program is based on average weather (1-in-2) and that the PRM, in part, provides a cushion should hotter-than-average weather occur. (Id.; see also Finding of Fact 11, p. 180.)
In a later LTPP decision, the Commission addressed the need for additional generation capacity in a region of southern California known as SP 15. Discussing PRMs under normal and adverse conditions, it suggested that the adopted PRM may not include protection for all risks to reliability:
In all likelihood, the state will need more than 1,783 MW in SP 15 to allow for retirements, ensure against execution and plant building risk, and maintain [a] 15%-17% planning reserve margin and adequate adverse condition reserve margin. (D.06-07-029, p. 39.)
In approving a power purchase agreement between Southern California Edison Company (SCE) and Long Beach Generation LLC, the Commission found that SCE would have a 19.1% PRM for summer 2007. (D.07-01-041, Finding of Fact 9, p. 28.)4 Although this exceeded the PRM policy of 15-17%, the Commission also found that:
A PRM is not the only measurement metric for reliability; the California Energy Commission (CEC) also looks at operating reserves under adverse conditions. (Id., Finding of Fact 12, p. 28.)
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Even though SCE has a predicted PRM of 19.1%, actual loads and resources may differ from forecasts. (Id., Finding of Fact 15, p. 29.)
Addressing a settlement regarding San Diego Gas & Electric Company's (SDG&E) application for a proposed Advanced Metering Infrastructure (AMI) project, the Commission discussed SDG&E's claim that, through AMI, SDG&E would be able to reduce its planning reserves. According to SDG&E, a possible long term benefit of reduced demand volatility brought about by AMI would be the ability to reduce the level of planning reserves by 1% (e.g., from 15% to 14%). Although the Commission found this to be a "too speculative benefit and too remote from the AMI Project to consider and quantify" for purposes of evaluating the AMI project, it acknowledged that the existence of AMI technology may be one of many factors upon which determinations of planning reserves are based. (D.07-04-043, pp. 62-63.)
2.3. Revisiting the PRM
Since the 15-17% PRM was established in early 2004, parties have continued to raise concerns about the determination of the PRM in ongoing procurement proceedings. Perhaps most notably, the CAISO filed a petition for modification of D.05-10-042 in which it asked that the Commission establish a 23% PRM for non-summer months. While denying the CAISO's petition without prejudice on procedural grounds, the Commission stated that "[w]e recognize the importance of revisiting aspects of the PRM at an appropriate time and in an appropriate forum." (D.06-12-037, p. 10.) The December 22, 2006 Assigned Commissioner's Ruling and Scoping Memo for Phase 2 of Rulemaking 05-12-013 provided that "consideration of updating the 15-17% planning reserve margin" was within the scope of the proceeding. However, in a subsequent ruling issued on November 19, 2007, the assigned Commissioner determined that the PRM should be reviewed comprehensively in a separate rulemaking. We affirm that ruling, and adopt this new rulemaking for the reasons stated therein and in this order.
2.4. Planning Reserves in Other Jurisdictions
Around the country, a variety of approaches are used to determine and set a proper level of capacity and reserves needed to maintain a desired reliability level. While some use deterministic modeling, other balancing authorities use a probabilistic modeling methodology to assess and set the proper levels of operating and planning reserves. The probabilistic approach focuses on setting capacity and reserve obligations relative to a reliability metric such as Expected Unserved Energy, LOLP, Loss of Load Expectancy, or more granular variations such as Hourly Loss of Load Expectancy.
1 California's electric generation market includes both utility-owned generation and merchant generation. CAISO-controlled grid depends upon both sources of generation.
2 ORA is the predecessor to the Division of Ratepayer Advocates.
3 The minimum PRM requirement that must be met by LSEs in connection with the RA obligation is 15%. However, for LTPP purposes, the Commission allowed a range up to 17% to account for lumpiness in investment. (D.04-01-050, Conclusion of Law 5, p. 193.)
D.04-10-035 accelerated the implementation schedule for the 15-17% PRM requirement from 2008 to June 2006.
4 D.07-04-049 modified D.07-01-041 and denied rehearing of it as modified. The findings of fact quoted here were not modified.
