V. Application of § 399.25 and Funding of Tehachapi Transmission Upgrades

Pub. Util. Code § 399.25,⁷ implemented as part of SB 1078 effective January 1, 2003, addresses funding of transmission facilities necessary to facilitate achievement of California's renewable power goals, as follows:

(a) Notwithstanding any other provision in Sections 1001 to 1013, inclusive, an application of an electric corporation for a certificate authorizing the construction of new transmission facilities shall be deemed necessary to the provision of electrical service for purposes of any determination made under Section 1003 if the commission finds that the new facility is necessary to facilitate achievement of the renewable power goals established in Article 16 (commencing with Section 399.14).

(b) With respect to a transmission facility described in subdivision (a), the commission shall take all feasible actions to ensure that the transmission rates established by the Federal Energy Regulatory Commission are fully reflected in any retail rates established by the commission. These actions shall include, but are not limited to:

(1) Making findings, where supported by an evidentiary record, that those transmission facilities provide benefit to the transmission network and are necessary to facilitate the achievement of the renewables portfolio standard established in Article 16 (commencing with Section 399.11).

(2) Directing the utility to which the generator will be interconnected, where the direction is not preempted by federal law, to seek the recovery through general transmission rates of the costs associated with the transmission facilities.

(3) Asserting the positions described in paragraphs (1) and (2) to the Federal Energy Regulatory Commission in appropriate proceedings.

(4) Allowing recovery in retail rates of any increase in transmission costs incurred by an electrical corporation resulting from the construction of the transmission facilities that are not approved for recovery in transmission rates by the Federal Energy Regulatory Commission after the commission determines that the costs were prudently incurred in accordance with subdivision (a) of Section 454.

We issued Decision (D.) 03-07-033 establishing procedures to implement § 399.25 on July 10, 2003, after the conclusion of hearings in this phase. We denied rehearing of D.03-07-033 in D.03-10-020.⁸

A. Positions of the Parties

Oak Creek asks that the Commission make affirmative findings pursuant to § 399.25 that Tehachapi upgrades are necessary to achieve renewable power goals and would provide benefit to the transmission network. Oak Creek claims network benefits both in correcting existing deficiencies and in accommodating new wind generation. Oak Creek points to on-going voltage/reactive power problems in the Tehachapi area, which have caused both wind generation curtailments and customer outages. Oak Creek maintains that a Tehachapi project would resolve the existing deficiencies and, because Oak Creek anticipates operation in parallel with the existing grid, would enhance operation of the entire grid. Oak Creek submits that the costs of at least the first 230 kV line should be rolled-in and recovered through transmission rates. It recommends that the Commission direct SCE to submit transmission rate filings to the Federal Energy Regulatory Commission (FERC) to implement cost roll-in.

The ISO, SCE, and PG&E respond that reliability problems in the Tehachapi area are already being addressed. The ISO acknowledges that recent upgrades to the 66 kV system to provide additional reactive power (VAR) support and increase the deliverability of wind generation have not been as successful as had been hoped and that Tehachapi wind generation continues to be curtailed sporadically. SCE explains that it has not been able to determine the needed level of VAR support because it has lacked certain technical data regarding existing wind generation.

The ISO, SCE, and PG&E assert that the Commission should not determine at this time whether a Tehachapi project is necessary to meet renewable power goals, whether such a project would provide network benefits, or the appropriate ratemaking treatment. These parties maintain that essential information necessary for such determinations will not be available until an RPS auction is completed, winning bidders are selected, interconnection applications are submitted, detailed system impact and facilities studies are performed, and alternatives are examined. SCE recommends, however, that the Commission take this opportunity to adopt a plan for implementing what SCE calls the "protective backdrop" in § 399.25(b)(4) to ensure that a utility is able to promptly recover costs in retail rates if FERC does not approve recovery of prudently incurred costs in wholesale transmission rates.

The ISO explains that, under current policies, ratemaking treatment depends on the nature of a transmission project. If the ISO determines that a transmission network upgrade is needed for reliability or economic reasons, the transmission owner pays for the upgrade and recovers its costs through transmission rates, assuming FERC accepts inclusion of those costs in the transmission owner's transmission revenue requirement. The ISO reports that FERC's policy has been that generators fund transmission network upgrades necessary to accommodate interconnection of new generation projects. Transmission owners may credit back to generators the cost of such upgrades, with cost recovery within five years if the project becomes and remains operational. Generators fund transmission facilities from the generating plant to the point of interconnection with the transmission grid (called "gen-ties") and also fund all studies required for the interconnection process.

Because a large Tehachapi project would be far more expensive than needed to correct existing reliability problems, the ISO and SCE assert that there is no reliability-based justification for rolling costs of such upgrades into transmission rates. The ISO recognizes, however, that rolled-in treatment may be justified if a project allows a utility to meet its RPS requirements in the most economic manner.

SCE takes the position that developers should pre-fund any Tehachapi upgrades used to connect new wind generation so that ratepayers and utility shareholders do not bear the financial risks. SCE maintains that this approach is consistent with FERC policy for network upgrades needed due to new generation. SCE also suggests that FERC may classify Tehachapi upgrades as gen-tie rather than network facilities,⁹ with a resultant requirement of developer funding. SCE submits that FERC initially classified transmission facilities to Diablo Canyon, Morro Bay, and Moss Landing generation as gen-ties even though the transmission facilities provide network loop configurations.¹⁰

B. Discussion

Section 399.25 requires that a certificate application for new transmission facilities be deemed necessary to the provision of electrical service if the Commission finds that the new transmission facility is necessary to facilitate achievement of renewable power goals. As we explained in D.03-07-033, § 399.25 provides the possibility of upfront ratepayer funding for new transmission facilities that the Commission determines are necessary to facilitate achievement of renewable power goals. With this arrangement, the utility would finance the transmission project and would request that FERC authorize cost recovery through transmission rates. Under this scenario, ratepayers would fund the costs, either in transmission rates authorized by FERC or in retail rates authorized by this Commission pursuant to § 399.25(b)(4). It is noteworthy that even if generators pay for transmission upgrades upfront, ultimately, ratepayers will pay through rates for any such investment deemed necessary, as per current FERC policy. Thus, the issue is who bears the initial risk of the investment, not necessarily who pays for it.

Contrary to some parties' assertions, a Commission order directing a utility to seek cost recovery through general transmission rates pursuant to § 399.25(b) for Tehachapi upgrades would not be inconsistent with FERC's current interconnection policies and would not trespass on FERC jurisdiction over interconnection agreements. FERC's Order 2003¹¹ provides independent transmission providers, such as the ISO,¹² flexibility regarding their interconnection and pricing provisions, subject to FERC approval.¹³ In both Order 2003 and in its white paper issued in its Standard Market Design rulemaking, FERC has invited the formation of Regional State Committees and FERC has made it clear that states' will have transmission-related decision-making authority in their ISOs or RTOs. This Commission will take all needed actions, as directed by § 399.25, to obtain FERC approval of the inclusion in transmission rates of costs of transmission facilities funded by the utilities to fulfill RPS goals. We have the reasonable expectation that FERC will approve actions we may take as we proceed with our statutory mandate to implement § 399.25.

Section 399.25 applies only to applications for a certificate authorizing construction of new transmission facilities. It would not apply to facilities that are not constructed by a utility and thus are not brought to the Commission for certification. An assessment of whether Tehachapi upgrades should be constructed by a utility or treated as gen-ties to be built by project developers may depend on the configuration of the facilities and their relationship to particular renewable projects. As a result, it would be premature for us to reach conclusions at this time regarding the proper classification of such facilities. We note that, while gen-ties built by project developers would not be eligible for upfront ratepayer funding under § 399.25, they may be eligible for supplemental energy payments consistent with § 399.15(a)(2).

In D.03-07-033, we determined that the Commission generally will make § 399.25 findings in the applicable CPCN or permit to construct (PTC) proceeding, based on the results of the RPS procurement process and General Order 131-D considerations of alternatives to the proposed project. Based on the record before us, including the CEC study, however, we can already reach a preliminary determination that some Tehachapi upgrades are necessary to facilitate achievement of renewable power goals. Since the Tehachapi area represents a significant cost-effective source of renewable power in California and the area has only sufficient transmission capacity to meet the power transfer needs of the existing resources in the region, it is foreseeable that transmission upgrades in the area will be necessary to meet California's RPS goals. The exact nature of the upgrades and the resource potential must still be established to determine if all of the resources can be developed in a way that is cost-competitive, taking into account transmission costs, and that Tehachapi projects are consistent with a best-fit procurement strategy. However, the need for Tehachapi upgrades has been developed sufficiently to allow us initially to determine for purposes of § 399.25(b)(1) that the first phase of Tehachapi network upgrades would provide benefit to the transmission network. The size and concentration of the Tehachapi wind resource leads us to the conclusion that there is an overall need for transmission upgrades in this area, even as we evaluate the particular needs of various segments of the upgrades in individual proceedings, consistent with D.03-07-033.

The need determinations in individual CPCN proceedings will relate to the particular projects and upgrades associated with that specific proceeding. In this decision, we are making an initial need determination overall with respect to the necessary contribution of Tehachapi wind in general to meeting RPS goals. Thus, these need determinations are separate and severable.

When a utility files a certificate application for Tehachapi upgrades, we will consider at that time the exact ratemaking treatment contemplated under § 399.25 and will also address project financing, as well as any additions to the record regarding need, as necessary. The Commission is very aware of its cost recovery authority under § 399.25 (b)(4) and will use that authority, as necessary, in such a consideration.

Because § 399.25 requires that the Commission determine that a certificate application is needed if we find that the transmission facilities are necessary to facilitate achievement of renewable power goals, a separate assessment of whether the project brings reliability or economic benefits would not be required for certification purposes. Thus, the issues raised in Rulemaking (R.) 04-01-026 regarding the assessment of reliability or economic need for new transmission projects do not pertain to findings of need pursuant to § 399.25.¹⁴

We decline to establish general policies at this time, as SCE requests, regarding how § 399.25(b)(4) would be implemented if FERC denies cost recovery for transmission projects for which the utility has sought cost recovery pursuant to § 399.25(b)(2). Whether FERC would deny such cost recovery is speculative at best and we believe that FERC will look favorably on transmission development designed to further renewable resource goals. Further, if FERC were to disallow the recovery of such costs in transmission rates, the appropriate way to reflect such costs in retail rates using our authority in § 399.25 (b)(4) may depend on the specific facts of the situation. Thus, we see no need to develop contingency procedures for implementing § 399.25(b)(4) at this time.

However, our choice today not to develop a general methodology should not be interpreted as an unwillingness to use this authority granted in SB 1078. On the contrary, we are inclined to use such ratemaking authority if FERC were to deny cost recovery. We believe this would likely be a fair approach given that the Commission is taking forward-thinking action in this decision to meet the goals of a public policy decision on renewables that is important to Californians, as articulated in SB 1078. As such, ratepayers must be ready to shoulder some of the burden of the risks inherent in moving towards the RPS goals.