III. Summary of Proposals and Comments

The pre-workshop proposals can be grouped into two categories: proposals advocating that the Commission should enact new policies now to support investment in new generation, or proposals suggesting that the Commission should "stay-the-course," to allow other policies, such as resource adequacy and the 2004 long-term procurement plans, which are already in place, to stimulate sufficient new generation.

A. The Joint Parties' Proposal

In advance of the March 14, 2006 workshop, a Joint Parties' Proposal (JP) was presented by SCE, PG&E, NRG, TURN, and AES. The Joint Parties argued that the Commission should adopt their cost and benefit proposal as a limited, interim mechanism to ensure that new generation gets built on time. The Joint Parties intend that their interim plan will be replaced by a Commission-adopted market structure that will support new generation investment, such as capacity markets or another durable market mechanism.

The Joint Parties ask the Commission to rule that as a transitional mechanism, the utilities, or another entity if feasible, may procure new generation within an IOU's distribution service territory, with the costs and benefits associated with these new resources allocated to all benefiting customers. Under the JP, "benefiting customers" is defined as all bundled-service customers, DA, community choice aggregators (CCA) and IOU customers who are located or locate within the distribution service territory of an IOU but take service from a local public-owned utility (POU) subsequent to the commitment date for new generation.⁸ PG&E filed a separate proposal advocating that the IOUs are the only viable entities than can procure new generation.

Under the JP, not only costs, but also benefits, would be allocated. Capacity and energy are purchased by the IOU as a bundled product through a contract for a new generating unit. All LSEs would be entitled to receive a share of the RAR credit. RA capacity credit would be divided among LSEs by a share of coincident peak, adjusted on a monthly basis to facilitate load migration. Implied in the JP is that the Energy Division (ED) and CEC would distribute the RAR credit through the existing notification mechanisms⁹ established in our RA program.

The Joint Parties' proposal is based on the premise that new generation is needed now in order for all LSEs, not just the three IOUs, to meet their individual RAR and to insure system reliability. The Joint Parties argue that the new generation is needed to ensure reliability and allow some aging units to retire, regardless of the source of the load growth¹⁰. The Joint Parties believe that in order to get new generation financed and built, the investor needs a long-term commitment. While an IOU is an entity with the resources to make such a commitment, PG&E and SCE believe that it would be unfair for their customers to pay the premium that new generation commands as compared with existing resources, while the entire state benefits from such an investment.

Under the JP, both utility-owned generation and power purchase agreements (PPA) for non-renewable portfolio standard (RPS) generation¹¹ would be eligible for recovery under this mechanism.¹² The JP argues the Commission should not allow an opt-out mechanism for any aspect of the requirement because any opt-out mechanism would require a review of how the LSE was deficient over a multi-year period, which is not currently definable.

The JP envisions the IOU managing the energy contracts and committing and dispatching the energy against forecast market prices in merit order according to least-cost dispatch principles and Commission and CAISO requirements. Any energy not scheduled or experiencing an outage would be submitted to the CAISO consistent with the must-offer obligation of resource adequacy resources. Then the net cost of this new generation capacity would be determined by adding the fixed cost and variable costs [linked to daily gas index] of the capacity and energy, then subtracting the energy and ancillary services revenues. Then the net costs of just resource adequacy capacity would be allocated to all customers. The costs would be allocated on a 12-month coincident peak among each rate group apportioned to all retail customers on a non-bypassable wire charge (NBC) per kilowatt hour (kWh).

The JP anticipates that certain ratemaking issues would need to be clarified in subsequent proceedings. For example, the IOUs would need to be authorized in future Energy Resource Recovery Account (ERRA) proceedings to establish a net cost balancing account. In the case of utility-owned generation, there would have to be separate entries into the Utility Generation Balancing Account (UGBA).

In separate comments supporting the JP, SCE provided schedules for a "Fast Track" and a "Standard Track" that it would use to issue long-term RFOs.¹³ Under the fast-track, SCE would submit an application by February 2007 for new resources that might come online by 2010. Under the standard track, SCE would submit an application by January 2008 for new resources that might come online by 2012. The purpose of the two-track system is to allow some resources that may already have permits and transmission interconnection studies complete to come online sooner, while also allowing for a wider range of opportunities to bid into the standard track solicitation.

In separate comments supporting the JP, as well as in A.06-04-012, PG&E stated its interest in having the cost-allocation mechanism apply retroactively to all of the new contracts recently selected in its long-term RFO.

B. Other Proposals

In addition to the Joint Parties, 15 other parties submitted pre-workshop proposals.¹⁴ Numerous proposals promoted the concept of "stay the course." Several of the key points raised in the pre-workshop proposals were also raised in post-workshop comments which are set forth in Appendix C. Some key issues from the pre-workshop proposals include:

· Constellation urged the Commission to recognize that the hybrid market structure is part of the problem because it creates an uneven playing field between utilities with guaranteed returns and investors without guaranteed returns.

· DRA urged the Commission to recognize that the uncertainty of customer base is driving the need for cost allocation policies.

· WPTF warned that there are no quick fixes, and it does not see a real urgency for immediate Commission action.

· AReM cautioned that the Commission should continue to support existing RA and LTPP policies. AReM also noted that ESPs cannot be expected to make long-term investments due to uncertainty about the continuation and expansion of DA.

· IEP argued that the Commission is asking the wrong question. According to IEP, cost allocation proposals are not the solution to the problem of lack of investment in new generation. Rather, it is the lack of regulatory stability and rules. IEP urged that the Commission should require all-source solicitations (that do not exclude existing resources) and improve the RFO and evaluation process to ensure fair and equal treatment. ¹⁵

· WPTF, IEP, Sempra Global, Mirant, and SDG&E are among those that argued that the Commission should move on immediately to implementing a capacity market in R.05-12-013.

· SDG&E argued that new policies are not required, since SDG&E was able to build new generation.

· Aglet suggested the Commission order the utilities to build new generation.

· CCC urged the Commission to adopt a Combined Heat and Power portfolio standard.

· Davis Hydro suggested the Commission should adopt proposals to enable pent-up demand for green power.

· TAS urged Commission to approve contract plant expansion using Turbine Inlet Cooling technology to expand capacity.

· WEM suggested the Commission prioritize new energy efficiency programs before adopting policies that support fossil resources.

· CARE supports a return to the IOUs making investments in new generation, along with entering into long-term contracts, but asks the Commission to ensure that the cost burdens for the new generation do not fall unfairly on the bundled ratepayers.

C. The Indicated Parties' Proposal

At the workshop on March 14, 2006, another proposal was introduced as the "Investco plan." The Investco plan responded to and modified the JP so that the entity that would procure the new generation would still be an IOU, but that the capacity and energy would be separated into two contracts. The Investco entity would assume the energy risk along with the tolling rights for a 10-year term. The IOU would hold an RFO and select a contract for a PPA tolling agreement. The entire contract would be unbundled to split it into these two components - the 10-year resource adequacy counting rights held by the IOU and a 10-year energy tolling contract held by the Investco entity.

The Investco plan was further modified by the Indicated Parties (IP)¹⁶ and renamed the Distco plan in post-workshop comments.

The Distco plan's recommendation, as presented by the Indicated Parties, is predicated on the Indicated Parties belief that if the Commission must do something to get new generation built, the JP as proposed is not satisfactory. The Indicated Parties fault the JP because it only addresses the need for reliability, but fails to ensure that the energy component of the backstop resources is managed in the most efficient manner possible. The Indicated Parties are concerned that the JP forces all energy from the new plants to be valued at the spot market prices over 10 years. To address this deficiency, the Indicated Parties state that the IOUs must unbundle the capacity and the energy from any new generation project, consistent with the Commission's encouragement of resource adequacy unbundled products, as well as attempt to optimize the energy value through an auction process. Pursuing a forward contracting model for the energy revenues will minimize customer exposure to spot market prices.

Among other modifications to the Investco model, the Distco plan provided for an annual or multi-year auction for the tolling rights to the energy rights of the plant for a term of up to five years (instead of selling it all at once for the full 10 years), and it allowed utilities to participate in the auction. These modifications addressed the concerns raised at the workshop that no entity might be interested in buying a 10-year tolling contract for the energy, as proposed by the Investco model.

Specifically, under the Distco plan, PPAs would be eligible resources that could bid into a utility solicitation process for new resources. Once chosen, the net RA capacity costs (total project costs minus the energy revenue benefits) from the project would be socialized to all utility customers through a non-bypassable wires charge just like the JP. Under the Distco plan, however, the IOU would not manage the energy dispatch process and only credit all customers with spot market revenues. Instead, the IOU would conduct an annual or multi-year auction that would allow market participants to bid on the energy component of the contract.¹⁷ Utilities'procurement departments would be allowed to participate in the auctions on behalf of bundled customers. If no bids were received, or if no bids were received that exceeded a minimum threshold, the default would be for the IOU to manage the energy dispatch and revenues in accordance with the terms of the JP. If an acceptable bid was received for the energy for a term of one or more years, then the net cost of the RA capacity (which is spread to all customers) would be fixed for the term of the energy contract.

The Indicated Parties believe a principle benefit of their Distco plan is the fact that the IOUs are not "managing the energy" and potentially using the large volumes of energy to flood the energy markets. The costs of the new capacity are spread to all customers, and the benefits of the energy are paid for by those who value the energy the most, which in turn minimizes the net cost of the capacity that is born by all customers.

D. Post-Workshop Comments

In general, the comments can be categorized into three groups: those urging the Commission to act now to effectuate new generation for California; those advocating that the Commission "stay the course"; and those recommending that the Commission do nothing now, but making suggestions in case we do. Post-workshop comments are summarized in Appendix C.

⁸ Joint Proposal, March 7, 2006, p. 1, fn. 2.

⁹ Currently, the ED notifies each LSE of its RA obligation.

¹⁰ Many ESPs argue that due to the suspension of DA, their customer load is not growing, therefore load growth is by bundled customers only.

¹¹ RPS eligible generation is subject to cost allocation mechanisms established in Commission decisions in the RPS proceedings and the JP does not include RPS generation.

¹² SCE indicated that it is only interested in applying this mechanism to PPAs, and to limit the mechanism to a 10-year period. PG&E wants the mechanism to apply to utility-owned generation and PPAs, for the life of the contract and/or asset.

¹³ SCE Proposal, March 7, 2006, p. 14.

¹⁴ Constellation, DRA; WPTF; AReM; IEP; Calpine Corporation (Calpine); Mirant; Sempra ; SDG&E; Aglet; California Cogeneration Council (CCC); Davis Hydro; TAS; WEM; and CARE.

¹⁵ The Commission is planning on addressing RFO procedures in Phase II of this proceeding.

¹⁶ The Indicated Parties included CLECA, CMTA, CCSF, Coral, DRA, Energy Users Forum, J. Aron, SVLG and Strategic.

¹⁷ The winning bid would receive an Energy Conversion Agreement at a fixed price of $/kW month and have the right to toll the unit as desired. The Resource Adequacy "counting" right would be retained by the IOU, to be credited as "RA capacity" to all customers that pay for the capacity.