4. Discussion

By way of definition, we refer to transmission facilities needed to bring power from the plant to the first point of interconnection with the existing transmission grid as "gen-ties." We refer to facilities needed to upgrade the existing transmission grid to ensure reliable electric service and full delivery of a generator's output with the added generation as "network" or "system" upgrades.¹² Under current FERC policy, new generators absorb gen-tie costs as part of the cost of producing power. With respect to network upgrade costs, current FERC policy requires a new generator to fund network upgrades for which the new generator is the "but for" causation. However, the transmission owner (e.g., the IOUs) must credit back those costs, with interest, in monthly payments amortized over a number of years beginning when the new generation is available to the grid. Thus, the renewable developer knows that it currently must finance the needed transmission network upgrades, but will receive that money back with interest once it comes on-line.

The language of § 399.25 does not modify the developer's cost responsibility for either gen-ties or network upgrades. The former continues to be funded by the new generator and the latter by ratepayers, under current FERC policies.¹³ The difference is that § 399.25 (b) provides the possibility of "rolled-in ratemaking" for network upgrade costs, which we define to mean that the developer would not have to fund network upgrades upfront and await recovery of those costs over time. Instead, ratepayers would fund those costs -either in transmission rates (authorized by FERC) or in retail rates authorized by this Commission. More specifically, the utilities would finance these transmission projects as part of rate base, with the associated costs recovered in rates.¹⁴ Under this scenario, ratepayers assume the financial risk of the generation projects actually coming on line.

Before the Commission can support rolled-in ratemaking for renewable transmission projects in the transmission rates under FERC's jurisdiction or consider including them in Commission-approved retail rates, it must make certain findings pursuant to § 399.25(b)(1). Specifically, the Commission must find that the transmission facilities: (1) provide benefit to the transmission network and (2) are necessary to facilitate the achievement of the RPS program. These findings must be supported by an evidentiary record.

As discussed above, the debate over the ALJs' proposed framework for implementing § 399.25 centers around when and how the Commission should make these findings. On the one hand, CalWEA argues that the findings can and should be reached before the RPS solicitation process is completed, based on transmission studies and other evidence related to the proposed facilities that are available prior to the CPCN or PTC filings. TURN generally supports CalWEA's position for projects in certain geographic regions that are rich in renewable resource potential, yet constrained by transmission limitations. The utilities, on the other hand, argue that ratepayers' interests are not served by commencing with CPCN and PTC applications for potential transmission projects before winning bidders are determined.

We agree with the utilities that it would be inefficient and counter-productive for them to file CPCN and PTC applications for all potential transmission projects before winning bidders are determined. CalWEA's proposed approach would require just that--irrespective of how well the proposed transmission project is defined in terms of size, location, costs and other factors, or how large the potential is for renewable generation projects in a particular region to win the RPS bid. As SCE points out, it can cost ratepayers between $1.5 and $3 million for each CPCN application filed by the utility for a transmission system upgrade.¹⁵

CalWEA's corollary proposal is also problematic. The renewables transmission study that the Commission will submit to the Legislature on December 1, 2003 is, by statute, dependent upon the renewables resource assessment that the CEC hands off to the Commission. It is intended to "provide for the rational, orderly, cost-effective expansion of transmission facilities that may be necessary to facilitate the development of renewable electricity generation facilities" identified by the CEC in its assessment.¹⁶

The CEC outlined the scope and schedule for its renewable resource assessment in a letter dated January 29, 2003.¹⁷ It plans to provide the Commission with an assessment by July 1, 2003 that identifies renewable megawatt additions by technology type (geothermal, solar, wind, etc.), and by general geographic area (e.g., Tehachapi, Salton Sea, San Gorgonio, Altamont Pass and Siskiyou County).¹⁸ We also note that the statutory deadline for submission of the transmission study may predate the completion of our RPS bid solicitation. Accordingly, the scope of work for our renewables transmission study will encompass the following:

"The purpose of this study is to present information to the Legislature about transmission upgrades that may be needed to interconnect and deliver new potential renewable generation, depending upon the results of the renewable power procurement process. .... The study will focus on identifying the scope and estimated costs of potential new transmission facilities, potential new line routes, new substation locations and, as appropriate, critical issues that might affect the development of those facilities. It is recognized that the scope and cost estimates of any potential new transmission facilities or upgrades identified in this process can only be as detailed as the resource development information provided by the CEC and the resource developers, and will be further dependent upon the order and timing of actual interconnections sought by the developers of renewable energy projects."¹⁹

Given these circumstances, we do not concur with CalWEA that any transmission project identified under the study should be presumed "needed" for the purposes intended under § 399.25-i.e., for certification and rolled-in ratemaking. Such a presumption would commit ratepayer funds for potentially hundreds of millions of dollars based on a general assessment of renewable resource potential, and without the benefit of knowing which projects would actually win the bid and where they would locate their generation facilities.

Moreover, CalWEA's interpretation of § 399.25 violates a basic rule of statutory construction. CalWEA asserts that "necessary to facilitate" is intended to mean that we "find only that the transmission project will enhance significantly the likelihood that renewable projects will be developed."²⁰ However, this interpretation would render the word "necessary" completely meaningless, in conflict with the rule of construction that statutes are to be interpreted according to their plain language, so that none of the language of the statute becomes surplusage.²¹

In our opinion, the Joint Ruling's interpretation of the statutory language is the only logical one:

"If the facility is an integral part of a renewables project approved pursuant to the RPS procurement process (i.e., a winning renewables bid), we believe that creates a prima facie finding that the transmission project will facilitate the achievement of the renewable power goals set forth in Article 16 of SB 1078. However, the statute specifically states that the transmission project must be "necessary" to the achievement of those goals. In our view, this requires a further level of scrutiny to ensure that the proposed project is the appropriate option among possible alternatives. Generally, it is only during review of the utility's CPCN or PTC application that the Commission has an evidentiary record with which to consider alternate routes, locations or configurations. For both type of applications, GO 131-D requires the utility to present reasons for selection of power line route or substation location, include comparisons with alternate routes or locations and discuss the advantages and disadvantages of each.²² Therefore, as a general rule, we envision that this finding is most appropriately made by the Commission in response to the utility's application for a CPCN or PTC for the transmission project."²³

Having said that, a set of transmission system upgrades related to renewable resource development may emerge from our renewables transmission study as being likely to be required over the next few years, based on the geographic location and magnitude of resource development projected by the CEC. The renewables transmission study will identify such upgrades and also describe what affirmative steps should be taken to plan for them. ²⁴ Such steps could include assessments of major environmental issues, land acquisition needs (and preliminary costs), among others. We will consider the report findings on these issues and direct the utilities to take such steps, as appropriate.

We are also proceeding with evidentiary hearings on the Tehachapi Transmission Project in advance of the RPS bid solicitation for the reasons described in the Joint Ruling.²⁵ In its comments on that ruling, SCE argues that evidentiary hearings are unlikely to yield useful findings based on the conceptual studies completed to date. We note that SCE makes these same arguments in its prepared testimony. In contrast, the wind developers argue in their testimony that the results of the conceptual studies and other factual evidence support Commission findings related to § 399.25. We will address these issues after hearing all the evidence in Phase 6 of our transmission investigation.

With minor clarifications, we are adopting the general framework proposed in Joint Ruling. First, we clarify that the framework applies to network transmission upgrades as defined above-and not to gen-ties. As discussed below, § 399.25 applies to applications for transmission line construction/upgrades subject to this Commission's siting jurisdiction. Gen-ties are considered part of the cost of the generation project and are sited by the CEC.²⁶

Second, as PG&E suggests, we clarify the purpose of the evaluation of "necessity" during the CPCN or PTC application process. The relevant question for that process is whether the project proposed to accommodate the interconnection of the winning renewable bidder is "necessary" for that purpose. The evaluation would not reconsider the selection of the winning generation project.

With these clarifications incorporated, we restate here the substance of the Joint Ruling:

All of the provisions of § 399.25 apply only to applications before the Commission that meet certain criteria. Accordingly, our primary task is to define what applications are subject to the requirements of Section 399.25. The relevant portion of subdivision (a) reads:

[A]n application of an electrical corporation for a certificate authorizing the construction of new transmission facilities shall be deemed to be necessary to the provision of electric 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 399.11).

First, there must be an application before the Commission from an electrical corporation for a certificate authorizing the construction of new transmission facilities. If there is no application before the Commission, § 399.25 does not apply. We note that the statute's language refers to § 1003, which addresses the informational requirements for projects that are subject to Commission review. This confirms our interpretation that § 399.25 applies only to applications for transmission line construction/upgrades subject to this Commission's siting jurisdiction. Moreover, in referring to the general informational requirements of § 1003, the statute does not specifically distinguish between applications for a Certificate of Public Convenience and Necessity (CPCN) and applications for a PTC, as we have defined these terms in GO 131-D. We conclude that § 399.25 applies to both CPCN and PTC applications before this Commission and, by definition, does not apply to gen-ties.

Second, § 399.25(a) contains a prerequisite that the Commission find that the new transmission facility "is necessary" to facilitate achievement of the applicable renewable power goals. If the network upgrade is an integral part of a renewables project approved pursuant to the RPS procurement process (i.e., a winning renewables bid), we believe that creates a prima facie finding that the transmission project will facilitate achievement of the renewable power goals set forth in Article 16 of SB 1078.²⁷ However, the statute specifically states that the transmission project must be "necessary" to the achievement of those goals. In our view, this requires a further level of scrutiny to ensure that the proposed project is the appropriate option among possible alternatives.

Generally, it is only during review of the utility's CPCN or PTC application that the Commission has an evidentiary record with which to consider alternate routes, locations or configurations. For both types of applications, GO 131-D requires the utility to present reasons for selection of power line route or substation location, include comparisons with alternate routes or locations and discuss the advantages and disadvantages of each.²⁸ Therefore, as a general rule, we envision that the Commission will make a finding of "necessity" in response to the utility's application for a CPCN or PTC for the transmission project. The evaluation would not reconsider the selection of the winning generation project.

A finding that the transmission project is "necessary" to facilitate the achievement of the renewables portfolio goals is reiterated in § 399.25(b)(1), which states in relevant part:

(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).

However, this section of the statute-which relates to ratemaking treatment, rather than project need-includes an additional requirement: the Commission must also find that the transmission facilities "provide benefit to the transmission network." Here again, we believe that the CPCN or PTC proceeding for the project is generally the appropriate forum in which to investigate and evaluate network benefits. To bifurcate this issue from the evaluation of project need and project alternatives that otherwise takes place during the CPCN and PTC review would, in our estimation, be confusing to public participants and could strain both the Commission's and interested parties' limited resources on transmission issues. Nonetheless, we recognize that evaluating network benefits in each separate CPCN or PTC proceeding could promote some inconsistencies in evaluation methods across proceedings. To address this, we direct that Energy Division monitor the methods being utilized across the various proceedings and develop recommendations to enhance the use of sound, consistent methods, as needed.

We recognize FERC's jurisdiction in the area of electric transmission, and our implementation of the statute does not attempt to modify or interfere with FERC's authority. However, we disagree with PG&E's contention that the authority granted to the Commission by § 399.25(b)(1), namely, to make findings that specific transmission facilities provide benefit to the transmission network, interferes with FERC's jurisdiction over transmission ratemaking such that it would be preempted by federal law. As discussed in Section 5 below, we rely on an interpretation of the statute that conforms with the basic rules of statutory construction.

In sum, as a general framework for incorporating the requirements of § 399.25 into the planning process, we adopt the following:

· The provisions of § 399.25 apply to network transmission facilities that come before the Commission in the form of a CPCN or PTC application. "Network" transmission facilities are defined as those that are needed to ensure reliable electric service with the addition of generation. The provisions of § 399.25 do not apply to transmission facilities needed to bring power from the plant to the first point of interconnection with the existing transmission grid.

· The procurement proceeding will develop the rules and procedures for the RPS planning process and RPS renewables bidding program. If the transmission facility is an integral part of a renewables project approved pursuant to the RPS process, (i.e., a winning renewables bid), that creates a prima facie finding that the network upgrade will facilitate achievement of the renewable power goals set forth in Article 16 of SB 1078.

· The Commission will make § 399.25(a) and § 399.25(b)(1) findings on whether a proposed transmission project is "necessary" to facilitate achievement of renewable power goals in the applicable CPCN or PTC proceeding, based on the results of the RPS procurement process and GO 131-D considerations of alternatives to the proposed project. The evaluation will not, however, reconsider the selection of the winning generation project.

· In the applicable CPCN or PTC proceeding, the Commission will make § 399.25(b)(1) findings regarding whether the transmission project undertaken to ensure reliable electric service with the addition of generation will also provide benefits to the transmission network.

· The Commission will continue to perform the appropriate CEQA review of CPCN and PTC applications, which may include consideration of project alternatives.

CalWEA and TURN correctly point out that today's adopted framework focuses on the results of the IOUs' procurement process. We believe it is premature to consider the applicability of § 399.25 to the procurement practices of other RPS-obligated retail sellers (electric service providers and community choice aggregators), until the rules for these sellers are developed in coming phases of RPS implementation. We will ensure, however, that treatment is consistent and equitable across RPS-obligated entities.

Finally, we note that IEP's concerns regarding the use of transmission cost proxies for the bid ranking process have been considered in D.03-06-071, and those costs will be developed in a further phase of this proceeding.