IV. Community Choice Aggregation (CCA)

On October 29, 2004, the proposed decision (PD) in R.03-10-003 mailed in anticipation of a Commission vote on December 2, 2004, implemented certain provision of AB 117⁴⁷ which permits local governments the opportunity to aggregate energy procurement on behalf of the consumers in their communities and establishing certain protocols for CCA. As of the date of the mailing of the PD in this proceeding we cannot anticipate with absolute certainty what protocols the Commission will adopt, or when, but we can refer to the PD for guidance in adopting this decision. Once the Commission issues a decision in R.03-10-003, the IOUs are to incorporate the directives from that decision as they make future planning and procurement decisions.

What is known in this proceeding is that much of the debate over the LTPPs raised by potential CCAs, municipalities or irrigation districts, specifically Chula Vista, Modesto and SSJID, centered on how the IOUs could/should plan prospectively and judiciously for upcoming CCAs, or other departing loads, so that there would not be excess energy if, or when, the CCAs became fully functional and able to serve customers previously served by one of the IOUs. What the potential CCAs, and others, want to limit is the amount of cost responsibility (CRS) that departing CCA customers would be required to pay for utility liabilities incurred on their behalf that are still extant when the CCA customers leave utility service. Section 366.2(h) of AB 117 dictates that the Commission shall authorize CCA only if the Commission imposes a cost recovery mechanism in accordance with the bill. The overriding policy behind the CRS is to make remaining bundled ratepayers, those still served by the utility, neutral to stranded costs left by the departing customers.

Based on the PD in R.03-10-003, it can be anticipated that the Commission's decision will implement a program whereby cities and counties can procure energy on behalf of their communities, but also protects those bundled ratepayers who do not have the option of transferring to a CCA from the possible cost impacts resulting from the departing customers. It is expected that that decision will adopt a methodology for estimating the CRS that will allow bundled customers to be indifferent to the CCA program, including a methodology for CCA customers to pay their share of the costs of DWR bonds and contracts, utility procurement contracts and other items. The PD anticipates that there will be a Phase 2 of R.03-10-003 that will address issues unresolved in Phase 1, including such topics as customer protections and switching protocols, billing and metering issues and reentry and switching fees.

Some parties offered guidance to the Commission on identifying trigger points whereby an IOU can proceed with confidence to stop procuring for potential departing load. TURN suggested that the delineation point should be when the CCA provides a binding statement of intent. Some suggested that the key point would be when a CCA files its implementation plan with the Commission; others suggested a more conservative approach of waiting until the Commission approves the CCA's plan. Obviously all parties, including the Commission, only want one LSE procuring for the same customer base at any one time. We will not determine a precise trigger point when an IOU can stop procuring in this decision.

Instead, we encourage cities and counties that are seriously considering CCA to approach their IOU and proactively seek strategies in which the two parties can share procurement risk going forward. Such strategies could include agreements between the IOU and CCA to allocate certain contracts to the CCA once it is formed, or the CCA could execute a binding notice of intent with a commitment to a target date, at which the CCA is responsible for energy procurement. The agreement should incorporate some element of penalty if the CCA does not make the target date. We support parties working together to seek the most efficient transaction between the IOU and CCA.

Our expectation in future procurement plans is that the IOUs shall incorporate reasonable anticipated CCA departing load. The assumption of the Commission is that the IOUs should acknowledge potential CCA departing load and identify which city and/or county has expressed intent to pursue aggregation, including MW estimates of this departing load, in future procurement plans.

A. Potential Stranded Costs Due To Customer Load Uncertainty

A major issue in this proceeding is the extent to which the utilities will be compensated for investments or purchases that they must make in order to meet their obligations to provide reliable service to their customers. The implementation of CCA, departing municipal load, and the potential for lifting, in some form or another, the current ban on allowing new direct access all create a great degree of uncertainty as to the amount of load the existing utilities will be responsible for serving in the future. Given the potential for a significant portion of the utilities' load to take service from a different provider, the utilities are concerned that they could end up over-procuring resources and incurring the stranded costs associated with these resources.

One solution to this problem, discussed elsewhere in this decision, is the adoption of load forecasts that seek to address, to the extent possible, the uncertainties over the future load that the utilities will be responsible for. Another solution is for the utilities to be entitled to recover any stranded costs occurring as a result of their efforts to meet their load obligations.

The IOUs support the concept of stranded cost recovery for their investments and believe it is a critical factor that needs to be resolved in order for them to plan their future procurement strategies. Consumer groups (TURN, ORA) worry that absent such a safeguard, the utilities' remaining customers would wind up responsible for these costs, violating the ratepayer indifference standard that the Commission has previously adopted. NRDC raises the concern that the "preferred" resources identified in the EAP require longer-term commitments. Limiting procurement choices solely to short-term options, many parties state, will result in a non-optimal resource portfolio and higher costs to all consumers.

Needless to say, the parties opposing the imposition of exit fees are either those most likely to depart the existing system (CMTA/CLECA, Modesto, SSJID) or ESPs that would serve this departing load. Modesto and Strategic/Energy, however, recognize that some stranded cost recovery might be allowed but only due to "unforeseen circumstances."

The above parties, generally advocate that the primary means to minimize or eliminate stranded costs is for the utilities to develop flexible portfolios with significant shorter-term purchases that could be rapidly reduced as load fluctuates.

WPTF also opposes stranded cost recovery, believing the utility should recover the costs of any excess capacity through a capacity market. Constellation makes a similar argument, proposing a "slice of load" approach wherein the utility would sell off a share of its resource commitments to other suppliers and that any new contracts entered into by a utility contain assignability provisions.

In general we agree that the utilities should be allowed to recover their net stranded costs from all customers, including the use of an exit fee. Such an approach best meets the Commission's goals of providing "the need for reasonable certainty of rate recovery" (as required under AB57 and noted in the June 4^th ACR) as well as best ensuring that California meets its energy needs.

Requiring departing customers to assume a fair share of their costs is also consistent with the Commission's policy of holding captive ratepayers harmless as required by state law.

As many parties noted, in its last procurement decision (D.04-01-050) the Commission stated that a flexible utility portfolio, consisting of a mix of short-, mid- and long-term resources would be the best mechanism to protect against utility over-procurement. However, since the issuance of this decision, the Commission has now made the utilities responsible for ensuring local reliability, accelerated the resource adequacy requirement from 2008 to 2006, and adopted RPS target goals resulting in the solicitation of new renewable energy sources by the utilities. These initiatives, combined with the existing overhang of utility retained generation and long-term DWR contracts significantly limit the flexibility that the utilities have to quickly adjust their resource portfolios. All of these resource additions benefit all existing customers by improving reliability and promoting renewable energy development.

There is also a potential mismatch between the types of resources that the utilities need to procure (primarily peaking and load following) and the resources that departing customers require (primarily base load with a lesser amount of peaking/load following capability). Thus it may not be possible for the utility to develop a resource portfolio that accurately matches the load profile of expected departing load.

Providing for stranded cost recovery provides a greater incentive for the utilities to enter into five year or longer contracts for existing capacity that many parties (IEP, Duke, Calpine, SCE, PG&E, ISO) are advocating as the optimal approach to ensure the availability of these resources.

Even WPTF, which does not support exit fees, is advocating for the utilities to enter into these longer-term contracts.

There is also the concern that the utilities may need to enter into new contracts (and/or construct) new capacity to ensure that California has sufficient resources toward the latter years of this decade. In order for these resources to be on-line when needed, it may be necessary to begin construction of these projects in the very near term. Almost all parties, including WPTF, agree that new construction would require a minimum ten-year contractual commitment. In the near-term, it appears that the utilities are the only entities capable of facilitating the financing of these projects through long-term contracts. ⁴⁸

New renewable projects, necessary for the achievement of the EAP and legislative goals, also require long-term commitments in the range of 10 to 20 years.

For the above reasons, it appears that the utilities may need to make longer-term commitments for capacity and energy that may become stranded at some point during the life of these projects.

The utilities should be allowed to recover the net costs of these commitments. This does not mean that the utility should recover the total cost of these commitments, only the uneconomic portion. Similar to the treatment of DWR energy commitments, the utilities should take appropriate steps to minimize the costs by selling excess energy and capacity needs into the marketplace. These other revenue sources (market sales, sales into the ISO's energy/ancillary services market, and potential sales into renewable energy credit or capacity markets should they develop) should be credited against the utilities' costs. It is too speculative at this time, as WPTF suggests that the utilities' sole recourse should be a capacity market which has yet to be developed. Additionally, as Edison and others note⁴⁹, there is no guarantee that revenues from a capacity market would equal the utilities' costs.

Allowing the utilities to recover stranded costs from all customers who benefited is consistent with recent Commission policy with regards to new resource additions. In both the SDG&E Reliability RFP (D.04-06-011) and in Edison's Mountainview decision (D.03-12-059) the Commission required that all existing customers of the utility were responsible for any potential stranded costs for a period of ten-years. Even requiring a ten-year commitment for new resources may still increase costs for captive ratepayers due to the need for the project developer to see accelerated cost recovery for their investments rather than amortizing these assets over a longer time period.

This decision therefore adopts the same 10-year standard for new fossil-fueled resources acquired by the utilities. We are also proposing a 10-year standard for new renewable resources, but seek comment if this time-period is sufficiently long enough that it will not deter the development of these resources. For all other shorter contracts, the utilities should be allowed recovery over the life of the contract.

As part of the issue of stranded cost recovery, SCE proposes that we change the direct access switching rules adopted by the Commission. NRDC requests that departing customers provide 10-years notice. Both of these proposals are premature at this time. They are better discussed if and when the Commission addresses the issue of allowing new direct access to occur, which, under present legislation, cannot be before expiration of the last DWR contracts in 2013.

⁴⁷ AB 117 (Chapter 838, September 24, 2002), which added Pub. Util. Code Sections 218.3, 331.1, 366.2, 381.1 and 394.25.

⁴⁸ See, for example, the comments of Calpine, the ISO, TURN and PG&E.

⁴⁹ TURN, NRDC.