5. Comments on Draft Decision

The draft decision of ALJ Gottstein and ALJ TerKeurst was mailed to the parties in this proceeding and Rulemaking 01-10-024 in accordance with Section 311(g)(1) and Rule 77.7 of the Rules of Practice and Procedure. Comments were filed on June 30, 2003 by PG&E, SCE, California Independent System Operator (ISO), TURN and Center for Energy Efficiency and Renewable Technologies (CEERT).²⁹ Reply comments were filed on July 7, 2003 by SCE.

In response to comments, we have made a number of language modifications to clarify the definition of terms and our intent in adopting procedures for implementing § 399.25 requirements. However, we have made no substantive modifications to the disposition of issues in the draft decision. Below, we discuss the major objections raised in comments.

PG&E and SCE take issue with the language in the draft decision that refers to "rolled in ratemaking." In part, their objections are a matter of semantics. In this decision, we use the term "rolled in ratemaking" to refer to a ratemaking process whereby developers would not have to fund network upgrades upfront and await recovery of those costs. Apparently, SCE and PG&E use the term "rolled in ratemaking" somewhat differently in FERC proceedings, i.e., in a manner that makes rolled in ratemaking and upfront funding by the generation developer not mutually exclusive. We clarify that our use and definition of the term is specific to today's discussion. We also clarify that the corollary to not having developers fund network upgrades upfront is a scenario where the utilities finance the transmission project and request cost recovery through rates.

PG&E argues that the draft decision errs in "assuming that section 399.25 somehow `provides the possibility' that renewables developers might not have to fund network upgrades upfront and await recovery of those costs over time."³⁰ In PG&E's view, the draft decision goes far beyond the requirements of § 399.25(b)(1) in implying that the Commission's network benefits findings could "then be used to circumvent federal requirements for the funding of network upgrades."³¹ PG&E argues that this would interfere with FERC's jurisdiction over transmission ratemaking, and as such would be preempted by federal law. SCE makes similar arguments in its comments.

We believe that the language of § 399.25(b)(1) does present the possibility of a ratemaking treatment for transmission facilities associated with renewables development that is different from the status quo, provided that certain findings are made based on an evidentiary record. To assume otherwise would ignore the Legislative requirement in § 399.25(b)(4) that we allow recovery of the utilities' costs of these transmission facilities in our retail rates, if FERC does not approve full recovery in the transmission rates under its jurisdiction and we find the costs prudently incurred. This provision only makes sense under a scenario where the utility finances the construction of the transmission facilities, applies to FERC for ratepayer cost recovery, and FERC does not authorize full recovery through the transmission rates under its jurisdiction. The language would simply be superfluous under PG&E's interpretation that this possibility does not exist and is automatically preempted by federal law. As the ISO points out in its comments, it may take considerable effort to harmonize implementation of § 399.25 with FERC requirements for interconnection (which are the subject of ongoing proceedings before FERC). PG&E clearly does not support any changes to FERC policy, as evidenced by the long discourse concerning this issue in its comments. Nonetheless, PG&E's interpretation of the statute violates the basic rules of statutory construction, whereas the ALJs' interpretation does not.

PG&E and SCE seem to read § 399.25(b)(4) as follows: If a renewable generator does not receive from FERC its desired species of rolled-in ratemaking, then the renewable generator may (subject to certain findings) obtain that desired species of rolled-in ratemaking from this Commission, not withstanding what FERC adopts. If and when the above contingencies occur, there may be a preemption issue, but we have not yet come to that pass. There is still ample opportunity to harmonize § 399.25 with FERC interconnection policy, both at this Commission and at the FERC.

Moreover, PG&E and SCE are simply incorrect in their assertion that the type of "rolled in" ratemaking for the transmission projects envisioned by § 399.25 violates FERC policy such that the doctrine of federal preemption is invoked. In this regard, we note that nowhere in their comments do either PG&E or SCE cite to a specific federal law or FERC rule that articulates this FERC policy as a legally binding requirement. Nor could they do so if they tried, because the FERC policy in question, which requires the developers of new generation to front transmission system network upgrade costs and to recover these costs in credits after the new upgrade is available to the grid, is precisely that-a policy; it is neither a law nor a rule.

The various FERC decisions cited in PG&E's comments reflect various instances in which that policy was implemented. However, the implementation by a federal agency such as FERC of a particular policy preference in various individual cases does not amount to the establishment of federal "law" that supports the application of the doctrine of federal preemption, and the states must be presumed to be able to implement their own alternative policy preferences in such matters unless federal law expressly or impliedly mandates otherwise. In this regard, we note that there are cases in which FERC policy actually supports the use of "rolled in" rate treatment (as we define the term in this decision) for transmission system network upgrades. Such upgrades typically provide system-wide benefits, and FERC has found that their cost should be borne by all users of the system. (See, e.g., San Diego Gas & Electric Company, 98 FERC ¶ 61,332 (2002). In sum, we find no basis for PG&E and SCE's assertions regarding federal preemption.

TURN and CEERT express concerns that the procedures adopted today are at odds with D.03-06-071, which we recently issued in Rulemaking (R.) 01-10-024 to establish our Renewable Portfolio Standard (RPS) program. We believe that these two decisions are indeed compatible, but make certain clarifications to the draft decision to ensure a clearer understanding of our intent.

We intend the procedures outlined above to represent our general approach for sequencing the RPS bidding process with the utilities' applications for construction permits, our associated environmental review, and determinations regarding § 399.25 ratemaking issues. In general, we believe that the public interest is best served by waiting until we know which projects actually win the bid and where they will locate, before making the determinations on project necessity and network benefits required under § 399.25. In the draft decision, the assigned ALJs describe at length the reasons for adopting this approach as the general rule, and we affirm that determination as being both consistent with the specific language of § 399.25 as well as the overall goals for our RPS program.

With respect to specific comments, we disagree with CEERT's characterization of these procedures as "putting at risk" or "likely assuring non-compliance" with the utilities' annual renewable procurement targets.³² More specifically, CEERT contends that compliance with the RPS procurement process set forth in D.03-06-071 requires that the Commission completes its need findings and review of CPCN applications for all winning bidders in the same year as, and preferably in advance of, each annual RPS solicitation. However, D.03-06-071 does not establish this expectation. Nor do we believe that such a timetable is reasonable for all winning bidders, particularly with respect to projects that require network transmission upgrades. In fact, we provided for a longer timetable by adopting a flexible compliance mechanism in D.03-06-071. Under that mechanism, a project (or group of projects) requiring new network facilities that take up to four years to construct is still eligible to win the "least-cost, best fit" solicitation for any given year.³³ Hence, the general procedures for implementing § 399.25 are not incompatible with the annual procurement process adopted in D.03-06-071, as CEERT suggests. Nonetheless, as we recognized in D.03-06-071, "least cost" will tend to favor generation with existing transmission facilities available.³⁴ It is not a flaw in our procedures, but rather an adherence to least-cost principles that may push renewable projects requiring such new transmission facilities further out into the future.

CEERT also objects to the proposed procedures on the basis that a winning bid cannot be identified without "findings first having been made as to how upgrade costs or network benefits will be allocated to a particular project."³⁵ We do not intend to identify a winning bid without conducting an assessment of the transmission costs associated with each renewable project. As described in D.03-06-071, we will be developing a "workable approximation of the costs to the transmission system imposed by each new renewable generator" in this proceeding, as well as addressing the issue of how the costs of new network facilities should be allocated among bidders within a common resource area, in a separate phase of this proceeding.³⁶ Bidders may also offer a description of the network benefits associated with their project, which will be reviewed by the utilities and Procurement Review Group during the bid selection process.³⁷ Hence, we will not proceed to select "least-cost, best fit" winning bidders without a reasonable assessment of the transmission costs associated with their projects and, as applicable, the network benefits.

What CEERT really seems to be objecting to (as did CalWEA in its earlier comments), is that developers may face some uncertainty as they prepare their bids with respect to how the FERC cost allocation and ratemaking issues will play out, including what our § 399.25 findings will be with respect to project necessity and network benefits. The statute clearly requires that such findings be supported by an evidentiary record. Workable approximations of new transmission facilities and the bidders' characterizations of network benefits considered in the ranking process do not represent record evidence. Moreover, as discussed in the draft decision, it is generally only during the review of the utility's CPCN or PTC application that we have an evidentiary record with which to consider alternate routes, locations or configurations sufficient for the finding of "necessity" required for the ratemaking issues under § 399.25(b)(1).³⁸ As a general rule, we concur with the assigned ALJs that conducting evidentiary hearings on network benefits in advance of the RPS bid soliciation or expecting the utilities to expedite CPCN or PTC applications for prospective bidders is unworkable. As indicated in D.03-06-071, we intend to proceed with the RPS solicitation assuming the continuation of current FERC interconnection and cost allocation practices for new generators, and developers should do the same.³⁹

At the same time, however, the procedures described in the draft decision were not intended to preclude this Commission from ever holding evidentiary hearings on § 399.25 issues (e.g., network benefits) for potential renewable transmission projects in advance of a RPS bid solicitation or filing of a CPCN or PTC. Nor do the procedures preclude us from directing the utilities to take affirmative steps to plan for transmission system upgrades that may emerge from our renewables transmission study. As a case in point, we have completed evidentiary hearings on the Tehachapi Transmission Project in order to explore whether findings related to § 399.25 can be made at this time. If the evidentiary record supports such findings, we will make them. However, they may need to be of a preliminary nature if we find that the project is not sufficiently defined at this juncture.

In sum, we affirm the general procedures for implementing § 399.25 set forth in the draft decision, with the clarifications discussed above. As TURN suggests, we also clarify that the calculation of transmission costs for the bid ranking process will be developed in this proceeding, consistent with our direction in D.03-06-071. Finally, we expand our definition of "network" or "system" upgrades to encompass what the ISO terms "Delivery Upgrades" in its comments.