VII. Procurement contracting authority: AB 57, upfront standards, cost recovery and ratemaking

A. Contracting Authority

The prior procurement proceeding, R.01-10-024, was the vehicle used by the Commission to put the IOUs back in the procurement business following the end of the deregulation experiment. Beginning in February 2002 and continuing up to the inception of this current procurement docket, the Commission issued the following decisions to direct the IOUs on filling their NOPs:

· D.02-08-071 authorized the utilities to procure for low-case forecast scenario residual net short (RNS) needs between the effective date of the decision and January 1, 2003 (multi-year contracts were allowed).

· D.02-10-062 authorized contract terms for up to five years for transactions entered into under the modified short-term procurement plans addressing 2003 procurement activities.⁸⁵

· D.02-12-074 authorized the utilities to hedge 2004 first quarter residual net short positions with transactions entered into in 2003.⁸⁶

· D.03-12-062 authorized the utilities to enter into contracts with terms up to five years to meet 2004 needs with delivery beginning in 2004.

· D.04-01-050 extended the procurement authority to the first three quarters of 2005, limiting the purchase authority to short-term contracts (contracts of one year or less duration).⁸⁷

1. Parties' Positions

Immediately following the issuances of the December 2003 and January 2004 Commission procurement decisions, PG&E requested an extension to its short term procurement plan (STPP) so it could enter into pre-approved transactions with terms up to five years during the term of its STPP, with changes suggested by PG&E in its petitions to modify (PTM) D.03-12-062 and D.04-01-050 and for automatic renewal of procurement plans. Now, faced with the new reserve requirements of 15-17% by June 1, 2006, from the recently issued RA decision, D.04-10-035, PG&E's NOP has increased over the next five years and increased the utility's market risk exposure. The ability to enter into multi-year agreements is necessary to implement PG&E's midterm resource strategy and to allow PG&E to acquire a resource portfolio with a mixture of contract terms to deal with load uncertainty over the next three to five years.⁸⁸

CAISO, SCE, TURN support and ORA does not oppose PG&E's request.

In its opening testimony, SCE proposes to have the AB 57 procurement plan be approved on a rolling five-year term. AB 57 does not say procurement transactions should be limited to five years or less duration, so there is no prescription against this modification, and PG&E supports it. In addition, SCE proposes to provide an updated capacity and energy position for seven years forward, based on its medium case scenario, beginning with a compliance advice letter submitted within 30 days of approval of its long term plan.⁸⁹

SDG&E states that short-term procurement plans should continue to be affirmed by the Commission as the upfront standards and criteria for short-term procurement pursuant to AB 57.⁹⁰

TURN supports additional authority to enter into contracts of up to five years' duration regardless of the initial delivery date. However, TURN recommends that contracts with duration of five years or longer be submitted to the Commission for pre-approval.

Duke urges the Commission to direct the utilities to undertake interim capacity procurement to meet the needs during the next three to five years; NRDC wants the Commission to require that the expected carbon emission costs should be used in procurement bid evaluation process; and Strategic argues the IOUs should be making shorter-term commitments, e.g. five years or less.

2. Discussion

It is reasonable to extend the IOUs' procurement authority on a rolling 10-year basis, given that the long-term procurement plans cover a ten-year period and they will be updated and reviewed every two years. We will diligently oversee how the utilities are using this authority. Therefore we authorize the utilities to enter into short-term, mid-term, and long-term contracts, with contract delivery start dates through 2014, provided that the IOUs submit the necessary compliance filings. Contracts with duration five years or longer be submitted with an application to the Commission for preapproval. We should note that the approval process of renewable contracts will differ depending on whether the contract is procured via an all-source or RPS solicitation. As determined in D.04-07-029,⁹¹ renewable contracts from an RPS solicitation will be submitted to the Commission for approval with advice letters.⁹² However, renewable contracts from all-source solicitations must be submitted with an application.

B. Cost Recovery for Utility Ownership and Turnkey Projects

1. Parties' Positions

PG&E proposes a ratemaking mechanism for cost recovery that includes the following features: upfront assurance of cost recovery; no opportunity for after-the-fact reasonableness review of project costs if the terms of the upfront approval are met; and a mechanism to allow cost recovery to begin as soon as the facility is operational. In addition, PG&E argues that the Commission's preapproval process should constitute upfront approval of the acquisition costs. That is, if the costs are determined to be reasonable in the preapproval process, and PG&E meets the preapproved upfront conditions, no after-the-fact reasonableness review should be necessary.

SDG&E wants the Commission to provide reasonable assurance of timely and complete recovery of the costs of approved, newly acquired turnkey utility-owned generation assets. SDG&E suggests that the existing Energy Resource Recovery Account (ERRA) provides reasonable assurance that the cost of future procurement contracts acquired will be fully recovered through ERRA mechanism, but the utility is not certain that ERRA provides assurance for cost recovery for new turnkey generation assets.

In D.04-06-011 we approved two turnkey generation projects for SDG&E: Ramco and Palomar. SDG&E, however, is concerned that the Commission did not establish specific revenue requirements for these projects, nor has the Commission specified the framework under which the turnkey costs will be recovered. In the interim, SDG&E believes that ERRA mechanism as established in D.02-10-062, provides SDG&E with reasonable assurance that costs for future procurement contracts will be recovered. SDG&E requests that the Commission provide equivalent assurance for cost recovery of turnkey projects as it has for other procurement resources.

In the LTPP proceeding SDG&E proposes a three-phase cost recovery framework for turnkey project cost recovery that starts with the filing for Commission approval of the project. In that filing, SDG&E will identify the rate-base and operations and maintenance (O&M) -related revenue requirements associated with the project for the first full calendar year of operation of the generation plant. SDG&E proposes to record costs associate with the turnkey plants to its Non-Fuel Generation Balancing Account (NGBA) and ERRA for recovery through SDG&E commodity rates. Under SDG&E's proposal, the Commission will adopt the annual revenue requirement of the applicable turnkey plant simultaneously with approval of the project. Prior to the operation of the turnkey generation unit, SDG&E will file an advice letter to incorporate any adjustments to the adopted revenue requirement.

The second phase of the framework covers the period from the end of the initial phase until the implementation of SDG&E's next Cost of Service (COS) decision to allow for annual attrition adjustments to the authorized revenue requirement.

In the third phase, SDG&E's revenue will be trued up to reflect the costs of these projects.

PG&E requests that the Commission provide timely cost recovery of utility owned generation when the facility starts serving utility customers, whether PG&E operates the plant itself or when it contracts with a third party to operate it. Under PG&E's proposal, PG&E would include the initial capital cost of the acquisition in its request for approval of the contract.

UCAN opposes SDG&E's proposal for cost recovery and argues that the Commission sets revenue requirements in the General Rate Case (GRC) and should not allocate separate revenue requirements for each asset owned by the utility in a non-GRC proceeding.

2. Discussion

We find SDG&E's mechanism reasonable and adopt it for all three IOUs. In the next few years, IOUs could add extensive new generation to their resource portfolios in order to meet their future resource needs. We believe a rate making mechanism needs to be in place to ensure proper and timely cost recovery for these facilities. Two issues need to be decided; the timing and the scope of the cost recovery. First, we determine the appropriate timing of the rate recovery. Both SDG&E and PG&E propose to start cost recovery when the new facility starts operation to serve utility customers. We agree and adopt this proposal.

Second, we adopt SDG&E's proposal for cost recovery. SDG&E proposes to establish rate-base and O&M-related revenue requirements associated with the generation plant and to use its NGBA and ERRA to record costs associated with the turnkey plants and for recovery through SDG&E commodity rates. PG&E proposes differently. In addition to the costs listed above, PG&E proposes that in some cases it may be necessary to request recovery for "financial burden associated with acquisition of utility-owned generation."⁹³ In PG&E's opinion, these costs may include planning and administrative costs of preparing for the construction or acquisition of the generation facilities, financing costs as incurred, and costs if the project is ultimately abandoned. We believe that some of these costs or risks will be considered in our review and evaluation of IOU contracts for turnkey projects and some will be considered as part of establishing the revenue requirement for these facilities. For example, we expect contracts for turn key projects to address provisions and penalties for project abandonment. As such these types of costs should not receive special recovery treatment. We reject PG&E's proposal in this respect.

C. ERRA Trigger Mechanism

The ERRA trigger mechanism requires the Commission to adjust procurement rates if the ERRA balancing account becomes undercollected or overcollected by more than 5% of the previous year's non-DWR generation revenues. The trigger mechanism is set to expire on January 1, 2006.

AB 57 added the following to the Public Utilities Code § 454.5 (d)(3):

Ensure timely recovery of prospective procurement costs incurred pursuant to an approved procurement plan. The commission shall establish rates based on forecasts of procurement costs adopted by the commission, actual procurement costs incurred, or combination thereof, as determined by the commission. The commission shall establish power procurement balancing accounts to track the differences between recorded revenues and costs incurred pursuant to an approved procurement plan. The commission shall review the power procurement balancing accounts, not less than semiannually, and shall adjust rates or order refunds, as necessary, to promptly amortize a balancing account, according to a schedule determined by the commission. Until January 1, 2006, the commission shall ensure that any overcollection or undercollection in the power procurement balancing account does not exceed 5 percent of the electrical corporation's actual recorded generation revenues for the prior calendar year excluding revenues collected for the Department of Water Resources. The commission shall determine the schedule for amortizing the overcollection or undercollection in the balancing account to ensure that the 5 percent threshold is not exceeded. After January 1, 2006, this adjustment shall occur when deemed appropriate by the commission consistent with the objectives of this section. (Emphasis added)

PG&E requests that the trigger mechanism remain in effect for the term of the long-term contracts be approved. DENA strongly supports PG&E's request on the grounds that the extension of the trigger mechanism will provide the certainty needed to maintain or improve PG&E's credit rating and will benefit PG&E customers, by ensuring that any decreases in procurement costs are passed on to the customers.⁹⁴ IEP joins in support with DENA.

We find that the ERRA trigger provides the IOUs assurance that procurement costs will be recovered in a timely fashion, and we keep the trigger in effect during the term of the long-term contracts, or ten years, whichever is longer.

D. ERRA Disallowance Cap

In D.02-12-074, the Commission adopted a disallowance cap applicable to utility administration and dispatch of allocated DWR contracts. The cap amount is equal to two times the utility's costs of procurement function.⁹⁵ In D.03-06-067 the Commission ruled the following: SCE's request to expand the disallowance cap established in D.02-12-074 to include all procurement activities violates the legislative mandate of AB 57, as codified in Pub. Util. Code § 454.5, as well as §§ 451 and 702.⁹⁶

The current disallowance cap is applicable to contract administration and dispatch from the integrated DWR-IOU portfolio. PG&E requests that the disallowance cap apply to all utility dispatch, including utility -owned generation, PPAs, and allocated DWR contracts on the ground that this would provide certainty in estimating the potential financial risk utilities face.

On July 8, 2004, the Commission issued D.04-07-028 which requires utilities to consider local reliability effects in their dispatch decisions. Potentially, this could impact the least-cost dispatch process that is an up-front standard that is included in procurement plans. PG&E argues that given the current concern in the investment community over the utilities' financial health, the Commission should clarify that the cap applies to all utility least-cost dispatch activities undertaken pursuant to the long-term plans approved by the Commission as that will provide needed regulatory assurance.

DWR does not oppose the development of a separate disallowance cap, but does oppose extending the disallowance cap to all IOU procurement activities, especially direct liabilities to DWR.

Consistent with our determination in D.03-06-067, as discussed above, that an extension of the disallowance cap violates legislative intent and the statutes, we reject PG&E's request.

E. Upfront Standards for Utility Procurement Products and Transactions

In previous decisions, The Commission authorized the following products and transaction processes:

In its PTM D.03-12-062, filed February 20, 2004, PG&E asks the Commission to clarify that for purposes of upfront standards for procurement transactions, "short term" means up to and including three calendar months, or one quarter, not "90 days." PG&E also wants a clarification that the IOUs can conduct competitive solicitations in an auction format. PG&E argues that the use of online auction techniques for competitive procurement falls within the guidelines presented in D.03-12-062 and D.04-01-050.

In response to PG&E's PTM, ORA agreed with the short-term definition, but opposed electronic auction authority since the proposal lacks details.

We clarify that D.03-12-062 authorized IOUs to conduct procurement using negotiated bilateral agreements for transactions of up to three calendar months, or one quarter, forward; and that utilities will consult with their PRGs for transactions with delivery periods of greater than three calendar months, or one quarter. We further clarify that D.03-12-062 authorized IOUs to conduct procurement using an electronic auction format for execution of competitive solicitations, among other transactional methods. The authorized products are good for short-, medium-, and long-term procurement.

F. SCE'S AB 57 Plan

SCE states that its proposed revision to its Existing AB 57 Procurement Plan⁹⁷ is a component of its long-term procurement plan. SCE further clarifies that it does not have a separate AB 57 long-term procurement plan and AB 57 short-term procurement plan. Instead, SCE has one AB 57 procurement plan which is a component of SCE's LTPP showing in this proceeding (SCE LTPP, July 9, 2004, Vol.2, p. 1). SCE states that the objective for each IOU's AB 57 procurement plan is to set the limits (i.e., the upfront achievable standards and criteria called for in AB 57), within which the IOU's transaction activity would be deemed reasonable. All transactions and actions that fall within the boundaries of an AB 57 procurement plan are compliant with the approved procurement plan and accordingly are assured cost recovery. Statute requires that a procurement plan contain upfront achievable standards and criteria.

On February 19, 2004, SCE filed a PTM D.03-12-062 (the 2004 Short Term Procurement Plan Decision). SCE's PTM presented arguments on twelve separate issues in the D.03-12-062 that, SCE contends, affect its ability to procure power and make it difficult for SCE to comply with portions of the decision as it is written. SCE's list of twelve requested modifications are set forth in its LTPP, Vol.2, pp.13-16, which we will not reiterate here. SCE, like PG&E, raised the 90-day vs. one-quarter issue.

We grant ten of SCE's twelve requested modifications with the exception of modifications seven and nine, as shown here:

1. "Modify language that would require an "unqualified certification" as a basis for authorizing SCE's proprietary risk model. The language of the decision must be modified because a certification of this level would be extremely difficult to obtain."

2. "Eliminate the requirement that SCE demonstrate that identified over-the-counter (OTC) brokers provide prices equivalent to those of exchanges. Allowing transactions from brokers only when the same transaction can be made with an exchange at an equivalent price is impractical."

With regard to an "unqualified certification" of SCE's proprietary risk model, we are not asking that the model be proven infallible. We are simply seeking an independent review of the internal validity of the model, that all the features of the model work as advertised, that the model is mathematically sound and that the assumptions utilized by the model are reasonable.

With regard to the requirement that SCE demonstrate that identified OTC brokers provide prices equivalent to those of exchanges, this is a reasonable upfront standard, consistent with AB 57. The use of transparent exchanges is one reasonable check on the competitiveness of a portion of SCE's procurement activity. We direct SCE to consult with its PRG regarding the specific implementation options that are available.

⁸⁵ D. 02-10-062, p. 47.

⁸⁶ D. 02-12-074, Ordering Paragraph 5.

⁸⁷ D. 04-01-059, p. 91.

⁸⁸ PG&E opening brief, p. 46.

⁸⁹ SCE opening brief, p. 67.

⁹⁰ SDG&E opening brief, p. 74.

⁹¹ D.04-07-029, pp.9-11.

⁹² We reserve the right to issue a resolution that orders the IOUs to file an application.

⁹³ PG&E's prepared Testimony, pp. 2-38.

⁹⁴ DENA opening brief, p. 13.

⁹⁵ D. 02-12-074, Ordering Paragraph 25.

⁹⁶ Id., Conclusion of Law 1.

⁹⁷ The "Existing AB 57 PP is the same as the "2004 Short-Term Procurement Plan - Confidential Version," dated May 15, 2003, as modified by the Commission in D.03-12-062 and submitted by SCE in Compliance Advice Letter 1770-E-A, dated February 23, 2004. These plans are also referred to at times in SCE's LTPP as the "Implementation Plan."