In this section, we discuss contested issues regarding development and consideration of transmission costs during the initial RPS procurement. Attachment A contains the comprehensive Interim Methodology that we adopt for this purpose.
The ALJ ruling proposed that, for interim purposes, the utilities prepare transmission cost estimates based on their most recent conceptual transmission studies, including the studies prepared for SB 1038 compliance and submitted on August 31, 2003 in this proceeding, conceptual transmission studies prepared in response to the March 19, 2004 ALJ ruling, and other comparable studies. The utilities would also rely on any System Impact Studies and Facilities Studies they may have for projects that have initiated the interconnection process and are in the ISO interconnection queue. Cost estimates in existing studies would be adjusted if needed to reflect that construction may occur in a different year than assumed in the study.
In their comments, no party took issue with the proposal that existing conceptual transmission studies be used in evaluating bids received in response to the initial RPS procurement solicitation. While CEERT supports the use of existing studies, it recommends that each utility's Transmission Ranking Cost Report be reviewed to permit adjustments for any inappropriate assumptions. CEERT asserts that, for some transmission upgrades purported to be needed for RPS procurement, it is impossible to distinguish between their use for RPS-related energy and their use for other potential energy flows.
PG&E responds that questioning the utility's assignment of transmission upgrade costs should not be allowed because this would not add any value and would only serve to slow down the RPS solicitation process. PG&E maintains that its Transmission Ranking Cost Report will rely on base cases that include all reliability-driven and economic transmission projects and that none of the costs for such projects would be attributed to RPS projects. PG&E asserts that the ISO's interconnection process is the appropriate forum for a renewables developer to dispute the attribution of a transmission upgrade to its project.
We find that it is reasonable for the utilities to prepare transmission cost estimates for use in evaluating bids received in response to the initial RPS solicitation using the most recent conceptual transmission studies, to the extent that System Impact Studies and Facilities Studies do not exist or are not sufficient. As ordered in D.03-06-071 and consistent with CEERT's recommendation, the parties should be allowed to review the Transmission Ranking Cost Reports and challenge their assumptions and results. In Section III.N, we establish the manner whereby parties may comment on the Transmission Ranking Cost Reports and on their use in the evaluation of RPS bids.
It may be difficult for individual developers to identify the extent to which they could reduce their costs and increase the competitiveness of their projects through sharing gen-tie facilities with other nearby projects. In addition, the proper demarcation between gen-ties and network transmission facilities may not always be clear.
To assist identification of the most cost-effective renewable projects in light of these difficulties, the ALJ ruling proposed that the utilities treat all transmission upgrades identified in their conceptual studies that would carry power from more than one renewable project as network transmission facilities, regardless of whether the utilities consider such facilities to be gen-ties or network transmission facilities. The cost of all such shared facilities would be included in the transmission cost adders rather than in projects' RPS bids. The shared facilities, like other transmission facilities, would be assigned to individual RPS projects in a manner that would allow the least-cost selection of winning bids. The ALJ ruling emphasized that the proposed approach would not prejudge the ultimate classification of the shared transmission facilities as either gen-ties or network transmission facilities.
In comments, SCE and PG&E take issue with this aspect of the ALJ ruling. PG&E maintains that the costs of all gen-tie facilities should be reflected in the price of power bid by the developers, citing the statements in D.03-06-071 that the cost of Direct Assignment facilities should be included in the bid and that interconnection facilities will be included in the Market Price Referent and therefore need to be included by the developers in their bids. PG&E argues that transmission costs should be classified consistently as either direct costs (to be internalized in the bid) or indirect costs (to be used in the second bid ranking process). PG&E explains that the methodology in the ALJ ruling for handling these costs could result in the submission of bids that do not reflect the total direct costs that renewables generators may be required to bear should they become winning bidders. As a result, the bid prices could later turn out to be insufficient to cover the developers' costs.
PG&E argues that only Federal Energy Regulatory Commission (FERC) can determine the classification of transmission facilities needed for RPS projects. PG&E maintains that under FERC precedent the dividing line between gen-ties and network facilities is the point at which new generation is first interconnected to the existing transmission system, and that the number of generation facilities using the gen-ties is not relevant to their classification under federal law. SCE and PG&E also point out that the Commission has argued before FERC that network transmission lines used primarily by multiple generators should be classified as gen-ties.
PG&E and SCE assert that exclusion of gen-tie facilities from the developers' bids could lead to inaccurate bid ranking results. They argue that this approach would lead to inequitable treatment of, e.g., a lone RPS generator located at the end of a gen-tie line compared to two RPS generators located near each other that would both use a single line, and would inaccurately reflect the true cost to ratepayers. PG&E submits further that treating the cost of shared gen-tie facilities as an indirect cost to be added to bids would send a potentially inaccurate signal to developers and would tend to encourage developers to site their facilities in other areas for which the Transmission Ranking Cost Report lists lower indirect transmission costs.
PG&E also submits that the utilities are in no position to estimate the cost of gen-tie facilities and that developers are better able to estimate the costs of facilities needed between their planned development and the first point of interconnection to the existing grid.
CEERT supports the treatment of shared gen-tie and network upgrades proposed in the ALJ ruling. CEERT submits that inclusion of shared interconnection facilities in the bid adder rather than in individual generators' bids is the only logical way to ensure that these facilities will be counted only once. CEERT maintains that, if such facilities were included in individual bids, generators would need prior knowledge of each other's bids in order to cooperatively design common facilities. Otherwise, the bids would include duplicative feeder lines, each spanning the entire distance to the existing grid. CEERT asserts that the purpose of the proposed methodology is only to evaluate bids, not to conduct precise engineering studies to construct actual facilities or to assign detailed cost allocation/financing responsibility for the transmission upgrades. CEERT maintains that these latter functions belong at the end of the process, not at the beginning.
CalWEA takes issue with PG&E's position that all facilities located before the point of interconnection to the existing transmission grid would be gen-ties. CalWEA points out that a network upgrade can expand the boundaries of the transmission grid, contrary to PG&E's implicit position that the boundaries of the transmission grid, once installed, never change.
On balance, we conclude that the method in the ALJ ruling for the treatment of shared transmission upgrades in assessing RPS bids should be modified. Contrary to PG&E's claims, whether shared gen-tie facilities are included in the developers' bids or in the transmission adder should not affect the ultimate least-cost, best-fit results. Thus, inclusion of such costs in the second ranking would not treat isolated generators inequitably or modify incentives for project location. However, we agree with PG&E that this approach may not lead to viable contracts with prices adequate to cover the developer's costs in instances where the shared network facilities are ultimately deemed to be gen-ties to be constructed by the developer.
At the same time, we are concerned that a procurement process that does not take into account that gen-ties may be shared by multiple projects would not reveal the least-cost renewable generation options. We therefore adopt the following steps to allow proposals for shared gen-ties to be considered in the bid evaluation and negotiation process between the utilities and renewable developers.
Each utility should describe in its Transmission Ranking Cost Report any transmission facilities identified in its conceptual studies that may be shared by more than one renewable project, but which the utility considers to be gen-ties rather than network facilities. The utility should specify both the location and capital costs of such facilities, and explain why it believes the facilities should be classified as gen-ties rather than network facilities. The developers may use this information in constructing their bids and may also contest the utility's determination through comments on the Transmission Ranking Cost Reports, as provided elsewhere in this decision.
To allow for the potential sharing of gen-tie costs, each bidder may choose to list its estimated gen-tie costs independently, and the utility will make iterative adjustments to its bid ranking to account for sharing of these costs among those bidders who are selected. While we recognize the extra analytic burden this requirement places on the utilities, they are directed to make their best efforts to find such cost-sharing opportunities, which, to the extent they can be captured, will result in lower costs to ratepayers. The utilities should present the results of this analysis to their Procurement Review Groups for review.
The adopted approach, in which the utility evaluates the possibility of shared gen-tie expenses for multiple bidders, is workable for the initial RPS solicitation but is not ideal. In another phase of this proceeding, we are considering whether current transmission planning procedures should be modified in areas where generation from multiple projects may be transported most economically over shared transmission facilities. The pending Proposed Decision in the Tehachapi phase of this proceeding would require a comprehensive transmission expansion plan for the Tehachapi area. If adopted, the collaborative study group created to develop this plan would also address whether this transmission planning approach should apply in other areas of the state with renewable resources. Such an effort would improve the identification of transmission facilities that may be shared among renewable projects and may lead to refinements in our future evaluations of annual RPS solicitations, hopefully starting in 2005.
We agree with CalWEA that, even under the utilities' view of the gen-tie/network facilities demarcation, network transmission upgrades may expand the grid and add new points of interconnection. If a utility includes any network upgrades in its Transmission Ranking Cost Report that would expand its grid and add new substations and thus new points of interconnection, the utility should specify the expected location of each new substation, so that project developers may assess their expected costs if they plan to interconnect at that substation. To the extent consistent with existing conceptual studies, the utilities should identify substation locations based on knowledge regarding both currently proposed and potential future renewable projects.
The ALJ ruling would reject both CalWEA's request that the Commission make a blanket determination that network benefits of transmission upgrades exceed their costs and, as a result, that no transmission costs be included in the assessment of RPS bids, and CalWEA's alternative request that hearings be held at this time to identify network benefits as offsets to transmission upgrade costs attributed to renewable projects. The ALJ ruling noted that, as provided by D.03-06-071, bidders may describe in their bids potential network benefits of their renewable projects, along with their projects' expected effects on local reliability, low income or minority communities, environmental stewardship, and resource diversity, for the soliciting utility's consideration in evaluating the bid. Other than mandating consistency and transparency, the ALJ ruling did not specify the manner in which a utility should consider such factors in assessing project bids.
In its comments on the ALJ ruling, CalWEA reiterates its position that transmission costs should be assessed to RPS bids net of identified benefits. It maintains that transmission bid adders that disregard network benefits would conflict with the statutory requirement that least-cost, best-fit resources be chosen on a total cost basis. Based on its view that most upgrades operating at voltages of 230 kilovolts (kV) and above will benefit the network, CalWEA suggests a rebuttable presumption that the net cost of transmission adders for such upgrades would be zero. For lower voltage upgrades, CalWEA recommends that the transmission owner be required to estimate savings due to lower line losses and also be required to estimate the increase in transfer capability across existing constrained interfaces. CalWEA maintains that, as the ISO implements Market Design 2002, it will be able to quantify the value of increased transfer capability based on locational marginal prices at each node of the ISO transmission system. CalWEA suggests that network benefits can be established through witness affidavits without the need for evidentiary hearings.
PG&E and SCE take issue with CalWEA's interpretation that the statute requires consideration of net transmission costs, since the statute does not mention, much less require, the use of network benefits to offset transmission costs. To the contrary, they oppose any consideration of network benefits in the rank ordering of RPS bids. PG&E and SCE maintain that, since reliability and economic transmission upgrades are already included in the utilities' grid expansion plans and in the base cases used for the conceptual studies, it follows that all of the costs of transmission projects triggered by winning RPS bids are due to the RPS projects and must be accounted for in evaluating the overall cost of the competing bids.
PG&E and SDG&E assert that an attempt to quantify purported network benefits would take much longer than CalWEA assumes and would require much more detailed information than is currently available. They explain that the existing conceptual studies are based on proxy facilities, simplified input from the potential resource developers, and simplified solution techniques. SDG&E and TURN note that CalWEA's suggestion to use locational marginal prices to value transmission upgrades is not possible until the ISO's Market Design 2002 is implemented. PG&E maintains that the economic benefits, if any, of network upgrades required by RPS projects cannot be quantified at this time, pointing out that a detailed methodology for calculating such benefits is being developed in another phase of this proceeding.
PG&E argues further that reductions in line losses should not be considered network benefits to be netted against transmission costs, because line losses are already allocated to the generators through Meter Multipliers. It maintains that line loss reductions cannot be counted as a benefit unless the generators are willing to lower the power cost commensurately.
TURN agrees with CalWEA that the increase in network transfer capability due to transmission upgrades is relevant and should be assigned value for purposes of a transmission cost bid adder. TURN urges the Commission to develop methods for estimating the value of new transmission projects in the integrated planning envisioned in R.04-01-026. TURN proposes an interim valuation methodology which would estimate the benefits of new network transfer capacity in excess of what an RPS project would need, with the value to be set at half the pro rata cost of the incremental transmission capacity.
CEERT agrees in general with the proposal in the ALJ ruling that network benefits not be litigated at this time but be reserved for future debate. In CEERT's view, the proposed interim methodology provides sufficient flexibility so that network benefits for most bids may be considered at the "back end" of the process. It proposes, however, that developers who believe that transmission upgrades related to their projects could confer significant system benefits be provided the option to have their bid ranked two ways: first with no network benefits assumed and then with the bidder's assumptions about benefits. If acceptance/rejection of the bid depends on whether system benefits are considered, the utility evaluating the bids would determine whether to consider system benefits, document that choice, and provide that documentation to the bidder, the Commission, and the Procurement Review Group (PRG). CEERT believes that at that point the normal review process and/or a generic dispute resolution process should be able to resolve the issue, if necessary, without creating any unmanageable complexity or delay. PG&E responds that CEERT's proposal would lead to unacceptable delay and is contrary to PG&E's position that network benefits should not be considered.
A general requirement that network benefits be quantified for use in the rank ordering of RPS bids should not be adopted at this time. Contrary to PG&E's and SCE's interpretation, § 399.14(a)(2)(B) would allow transmission costs to be considered net of established benefits in the ranking process. Also contrary to PG&E's statement during the PHC, our determination in D.03-07-033 that evaluation of network benefits for purposes of § 399.25 should be undertaken during a certificate proceeding in no way limits our ability to consider network benefits in other forums for other purposes, including the RPS procurement process. However, there is not adequate information to establish for purposes of the interim RPS procurement whether network benefits would occur due to specific network upgrades. Nor do the analytical tools exist at this time to quantify such benefits. We intend to consider network benefits in future RPS solicitations to the extent feasible. In particular, we expect that the development of a methodology for assessment of the economic benefits of transmission projects, which is underway in another phase of this proceeding, will be useful in this regard.
CalWEA's urging of the adoption of a blanket assumption that the benefits of transmission upgrades for 230 kV and higher systems are equal to or exceed the costs of such upgrades is unrealistic. As other parties have pointed out, the Commission does not utilize such an assumption in our consideration of other transmission projects. Nor should we adopt such a blanket assumption for the utilities' least-cost, best-fit analysis of RPS bids.
We agree with the ALJ ruling that holding evidentiary hearings on network benefits before the initial RPS procurement is not desirable. As CalWEA has acknowledged, network benefits are not easily quantifiable and some may not be near term. In light of the long history and on-going efforts to quantify economic benefits of transmission upgrades, such an undertaking would be unlikely to yield usable results without significant delay of the initial RPS procurement. Such delay would hamper the Commission's ability to meet its accelerated RPS goals. Given that the ability or a method to quantify network benefits has not been established, CalWEA's suggestion that network benefits be assessed on the basis of witness affidavits is also unworkable.
For the same reasons, we do not adopt CEERT's suggestion that the utilities be required to rank a project bid on the basis of the proponent's assumptions about possible network benefits. Disputes between the developer and the utility over potential network benefits, which we view as likely based on the extensive debate to date, would return to the Commission for resolution. The Commission would be in precisely the position it is in now, with no objective basis for assessing the merits of either side.
Similarly, TURN's suggestion that the benefits of increased network transfer capacity be valued at one half the pro rata cost of the incremental capacity, while perhaps more objective than CalWEA's and CEERT's proposals, should not be adopted because it is arbitrary.
Recognizing the complexities involved, D.03-06-071 established the goal that transmission cost estimates used in the procurement process reflect a workable approximation of transmission upgrade costs. The approach in D.03-06-071, in which bidders may describe expected network benefits in their bids and the utility must consider this information in evaluating the bid, is a reasonable approach at this time. While we do not adopt specific instructions regarding the evaluation of network benefits, particular projects may provide clear benefits to the transmission system. We direct the utilities to consider this prospect in evaluating bids. As specified in Attachment A, the utility's consideration of potential network benefits should be consistent and transparent.
Under the approach proposed in the ALJ ruling, the utilities would develop transmission cost estimates for their Transmission Ranking Cost Reports that allow delivery of the full output of the renewable projects. If a project has System Impact Studies and Facilities Studies that do not address deliverability needs, the utility's transmission cost estimates in the Transmission Ranking Cost Report would still include deliverability costs, unless a contract has been signed that provides for curtailment in lieu of full deliverability. Projects would be allowed to submit bids that provide for less-than-full deliverability of project output, e.g., curtailments when transmission is constrained. The utility would then assess, on a case-by-case basis, whether and the extent to which the published transmission cost estimates should be modified in assessing such projects' bids.
CalWEA asserts that the ALJ ruling's proposed treatment of curtailable projects does not take into account a generator's right to avoid network upgrade costs. It maintains that generators have an unqualified right under FERC's Standard Large Generator Interconnection Procedures, established in FERC Orders 2003 and 2003-A, to interconnect as an Energy Resource and use the as-available transmission capability of the transmission provider. Alternatively, the generator may choose to be interconnected as a Network Resource.3
CalWEA asserts that utilities should not be given the discretion, as proposed in the ALJ ruling, to determine whether transmission cost estimates should be modified for projects that choose interconnection as an Energy Resource. CalWEA maintains that the Commission should require that a lower transmission cost adder be used if, by opting for Energy Resource treatment, the generator causes lower cost (or zero cost) transmission upgrades.
In CEERT's view, the treatment of curtailability proposed in the ALJ ruling provides sufficient flexibility for most bids regarding curtailability, which would be considered at the "back end" of the process. CEERT proposes, however, that developers who believe that curtailment/generator dispatch is an appropriate alternative to transmission expansion be provided the option to have their bid ranked both ways, i.e., with and without the bidder's assumptions about project curtailability. CEERT maintains that many transmission paths are congested only 10 to 50 hours per year and that it makes little sense to require a bidder whose project could otherwise deliver 99 to 99.5% of its energy to support an expensive upgrade that may be used less than 1% of the time. CEERT recommends that, if acceptance of a bid depends on whether curtailment/generator redispatch is considered, the utility evaluating the bids should be required to determine whether to accept curtailment/generator redispatch, document that choice, and provide that documentation to the bidder, the Commission, and the PRG. CEERT believes that at that point the normal review or dispute resolution process should be used to resolve the issue, if necessary.
TURN agrees with CEERT and CalWEA that the utilities should model transmission costs with and without curtailment provisions. In its view, if modest levels of curtailment would avoid a substantial transmission investment, this option should be considered in evaluating total bid costs. TURN suggests that bidders desiring curtailability be directed to specify the maximum level of acceptable curtailment, with bid prices submitted in connection with a curtailment offer assuming the maximum level of acceptable curtailment. TURN recognizes that the capacity value of such resources may be downgraded as part of the resource adequacy determinations ongoing in R.01-10-024.4
PG&E points to the "challenges" of relying on curtailment and redispatch options for purposes of transmission planning. PG&E maintains that, while dispatchability and curtailability may be helpful in matching aggregate resource levels to aggregate load levels, curtailment or generator redispatch can have undesirable effects when used to avoid building needed transmission upgrades. PG&E submits that the ISO would have to approve reliance on such schemes in lieu of transmission upgrades as part of the interconnection process, which would require much more detailed studies than are contemplated by the ALJ ruling. PG&E suggests that renewable generators can request an interconnection study through the ISO interconnection process and submit the resulting transmission cost estimates with their bids. PG&E raises an additional concern that, if resources are not available due to inadequate transmission capability, load may be curtailed. PG&E does not believe that the Legislature intended to compromise reliability when it mandated the RPS process.
SDG&E describes that, in addition to a reduction in transmission costs, curtailability could reduce expenditures for Firm Transmission Rights or, under the new market design, Congestion Revenue Rights,5 and could reduce losses on the resale of power sold to avoid congestion. SDG&E submits, however, that these benefits would be extremely difficult to quantify for the term of a contract and that analyzing each bid with and without transmission upgrades would dramatically increase the analytical effort for bid evaluation. SDG&E argues further that the delivery from a curtailable resource would be unknown, frustrating a utility's ability to plan for attainment of its RPS annual goals.
CalWEA's assertion that generators have a right to interconnect as an Energy Resource or a Network Resource is not consistent with current practices in California. The distinction in FERC's Standard Large Generator Interconnection Agreement between Network Resource Interconnection Service and Energy Resource Interconnection Service is based on eastern ISOs which have capacity markets and thus two levels of transmission service. These options are not offered in California through the ISO's tariffs.
In D.03-06-071, we recognized that the utilities may favor curtailability and dispatchability as attributes of bids. At the same time, we support the establishment of a deliverability standard in California, which would enable generators to meet the utilities' reserve requirements established in D.04-01-050. We support the ability of the utilities, with regulatory approval, to build and pay for, on a rolled-in basis, transmission system upgrades necessary to provide full deliverability of a generator's output. Until there is a deliverability standard, the utilities should assess RPS bids that propose curtailability as an attribute of their projects on a case-by-case basis. We do not require that they perform bid rankings with and without curtailability assumptions, as CEERT requests.
The guidelines in the ALJ ruling do not specify how, in this first year, a utility should assess transmission costs for projects that propose curtailability as an alternative to transmission upgrades or how it should value such bids. The best method of determining the feasibility of curtailability proposals appears to be through System Impact Studies and Facilities Studies. We direct the utilities to evaluate bids for projects that demonstrate reliable curtailability through such studies on that basis.
The same degree of certainty cannot be obtained from the conceptual studies used to evaluate transmission needs of projects without System Impact Studies or Facilities Studies. As a consequence, we do not order the utilities to evaluate curtailability proposals that rely only on the conceptual studies. However, on a case-by-case basis, there may be real benefits to ratepayers if generation can be curtailed in some limited amount and thus avoid costly transmission upgrades. For this year, the utility may use its judgment in evaluating these potential benefits, subject to the guidance expressed herein and the adopted dispute resolution process. Curtailability benefits may be captured more accurately in subsequent years' transmission cost analyses.
While we will give latitude to the judgment of the utility in this regard for projects that do not have System Impact Studies or Facilities Studies, we do not want to impose unnecessary transmission costs or prevent otherwise desirable projects from going forward if limited amounts of curtailability can in fact be managed. Like network benefits, the utility should document that it has considered curtailability proposals in a manner that is consistent and transparent to the Commission when it reviews proposed RPS contracts.
The ALJ ruling would reject CalWEA's recommendation that dynamic line ratings be used in the transmission cost estimates. In its comments, CalWEA reiterates its view that, by taking wind conditions into account, transmission requirements for wind generators can be reduced substantially. CalWEA submits that dynamic ratings are presently in use in multiple portions of the ISO grid.
SDG&E and SCE support the treatment of line ratings in the ALJ ruling. SDG&E submits that the application of dynamic line ratings is very specific to climate and other locational factors and is based on many months of studies even for a single line. It maintains that the use of dynamic line ratings is largely experimental and has not been accepted for day-to-day operations. It points out that the analysis needed to use dynamic ratings goes well beyond the level of analysis in the conceptual studies. SCE maintains that dynamic ratings would not be appropriate in the Tehachapi area, for example, because wind does not blow uniformly along the path of the transmission routes being considered.
We conclude that dynamic line ratings should not be used in determining needed transmission upgrades for purposes of evaluating the first RPS bids. Typical ambient conditions are taken into account in establishing line ratings for planning purposes. Dynamic line ratings, by their nature, reflect operating conditions that are not pervasive enough to be considered in reliability planning studies. We recognize, however, that dynamic line rating technologies are evolving, and we leave open the possibility that future RPS bid evaluations may appropriately incorporate them.
The ALJ ruling would reject CalWEA's suggestion that expected VAR characteristics of wind generators be taken into account in development of transmission cost estimates. Except for projects with completed System Impact Studies and Facilities Studies, the utilities are to develop transmission cost estimates without reference to specific projects. Developers would be allowed to submit VAR characteristics of their proposed projects, to the extent known, as part of their bids, and the utilities would be allowed to take this information into account in assessing the bids.
In comments, CEERT and CalWEA express concern that, in the conceptual studies, the utilities may have modeled wind generators as large VAR consumers and thus may have assumed the need for external devices to provide extra voltage support or may have underestimated the transfer capability of transmission lines designed to serve wind generators. They point out that current FERC policy requires that all generators, including wind generators, be roughly equivalent in voltage support obligations. CalWEA describes that modern wind designs employ static VAR compensators and capacitor banks to provide VARs that are closely calibrated to the VAR consumption of the machines and to the VAR needs of the local grid. CalWEA explains that these modern designs can provide voltage support benefit even when wind generators are not producing power, a capability not conferred by synchronous generators. CalWEA submits that the utilities should be required to assume that wind generators can operate within industry VAR requirements normally imposed on synchronous generators and that the ability of modern wind designs to provide voltage support should be reflected in transmission cost estimates.
PG&E states that it does not disagree with the proposal in the ALJ ruling that developers be allowed to submit VAR characteristics as part of their bids and that utilities be authorized to take this information into account in assessing the bids. In its opinion, however, it is unlikely that the value of VAR support would justify an adjustment of the transmission cost adder. SCE expresses a similar view.
Comments on the ALJ ruling raise two separate VAR-related issues: (1) whether in developing transmission cost estimates the utilities should assume that wind generators will be net consumers of VARs, and (2) whether generators should be allowed to document in their bids that they will be net producers of VARs and have their bid value adjusted upward commensurately.
Regarding the first concern, in estimating transmission costs in the Transmission Ranking Cost Reports the utilities should assume that wind generators will utilize modern technologies that employ VAR compensators and capacitor banks, in accordance with industry standards. Thus, they should not increase transmission costs assessed to wind bids due to concerns that the projects may be VAR consumers. Second, the utilities should consider any proposals they receive for VAR production as they assess the RPS bids.
In its comments, CalWEA submits that the sizing of transmission facilities should take into account the fact that maximum coincident generation from clusters of wind generation is materially less than nameplate generation, with the difference for a large resource area like Tehachapi being approximately 15%. This issue was not addressed in the ALJ ruling. CalWEA submits that utilities routinely consider load diversity in designing transmission and distribution systems and that diversity of wind generation similarly should be factored into the transmission cost determination. CalWEA maintains that, for example, SCE has not taken this factor into consideration in its conceptual studies for Tehachapi. SCE responds that the coincidence factor does not reduce the cost of facilities by 15% and that the cost estimates in SCE's conceptual plan for Tehachapi properly reflected the expected costs of facilities needed to interconnect wind generation.
CalWEA raised this issue for the first time in its comments on the ALJ ruling. We do not have sufficient information to determine whether or the manner in which the coincidence of wind generation should be taken into account in planning transmission upgrades for wind generation. As a result, we do not require that the utilities modify their conceptual studies in this regard. However, we would be willing to consider this matter as a possible refinement in development of future Transmission Ranking Cost Reports.
As described in the ALJ ruling, transmission cost estimates should reflect phased upgrades, with the most cost-effective upgrades assumed to be built first. No party took issue with this general approach. There were comments, however, regarding the manner in which information regarding the phasing of transmission additions should be reported in the Transmission Ranking Cost Reports.
PG&E's transmission cost proposal submitted in R.01-10-024 anticipated that three levels of transmission cost estimates for each geographic cluster of renewable projects would be included in the Transmission Ranking Cost Report. The methodology proposed in the ALJ ruling would increase the number of levels of possible transmission development to be reported.
In PG&E's proposal submitted in R.01-10-024, the base level of transmission capacity identified as Level 1 would reflect the available transmission capacity taking into account all upgrades planned for generation projects in the ISO interconnection queue. PG&E's suggested Level 2 would reflect the lowest-cost (or most cost-effective) network upgrade after upgrades for projects in the ISO interconnection queue, and PG&E's suggested Level 3 would include the combined capacity of all additional network upgrades needed to accommodate the entire cluster of renewable generation.
In the methodology in the ALJ ruling, the base level of reported transmission capacity (Level 1) would be the excess capacity expected to be available excluding any upgrades planned for projects in the ISO interconnection queue. Level 2 transmission capacity would reflect the capacity expected to become available due to upgrades for the first project in the ISO interconnection queue for which transmission upgrades are needed, with an additional level created for each project in the ISO interconnection queue for which needed transmission upgrades have been identified. Subsequent levels (identified as Level 3 in the ALJ ruling assuming one project in the ISO queue with needed transmission upgrades) would reflect the transmission capacity expected to become available with the lowest-cost (or most cost-effective) network upgrade in addition to upgrades for projects in the ISO interconnection queue, with an additional level created for each network upgrade needed to accommodate the total amount of generation in the identified cluster.
In its comments on the ALJ ruling, PG&E states that it agrees with the portion of the ALJ proposal that would require separate reporting for each distinct network upgrade needed to accommodate renewable projects not in the ISO interconnection queue. PG&E takes issue, however, with the proposed requirement that the utilities separately identify the available transmission capacity excluding upgrades for projects in the ISO interconnection queue and the transmission capacity created by each upgrade planned for projects in the ISO interconnection queue. PG&E maintains that this level of detail has no apparent purpose. Because PG&E's existing conceptual studies included all transmission capacity planned for projects in the ISO queue, PG&E maintains that it may not be practicable to report Level 1 and Level 2 transmission capacities and costs separately as proposed in the ALJ ruling.
In its reply comments on the ALJ ruling, CEERT agrees in part with PG&E's recommendation that the utilities not be required to "back out" from the Level 1 base case those transmission upgrades planned to accommodate generation projects in the ISO queue, to the extent that such generation projects are non-renewable or are not associated with a planned RPS solicitation.
CalWEA agrees with the approach in the ALJ ruling. It points out that if a generation project in the ISO queue fails, the cost of network upgrades currently planned for that project may be imposed on the next generator that is in the same cluster area. In its view, the objective of the Transmission Ranking Cost Report is to report all upgrade costs associated with a cluster. In addition, to the extent generators already in the queue bid in the auction, the upgrades associated with those generators should be reflected in the bid adder for those projects. CalWEA is concerned that PG&E's approach would not allow the cost of network upgrades associated with generators in the ISO queue to be reflected in their bid adders.
We confirm that the Transmission Ranking Cost Reports should include separate reporting for each distinct network upgrade needed to accommodate renewable projects that have not had transmission upgrades identified through System Impact Studies or Facilities Studies, consistent with the ALJ ruling. Because of feasibility concerns raised by PG&E, we do not require (but would allow) the utilities to separately identify in their Transmission Ranking Cost Reports a base case that excludes transmission capacity identified through System Impact Studies and Facilities Studies for projects in the ISO queue and, thus, included in the base cases in their conceptual transmission studies.
CalWEA is correct that some of the projects in the ISO queue may not ultimately be built, with the effect that the costs associated with necessary transmission may be attributed to the next project in line to interconnect. However, the transmission costs of projects with completed System Impact Studies and Facilities will not be ignored in the adopted bid adder process. Costs identified in System Impact Studies and Facilities Studies, adjusted if needed for deliverability as discussed in Section III.D, will be used in developing the bid adder for the project in question.
While we do not require that the utilities report a base transmission case excluding projects in the ISO interconnection queue, they should still report the results of existing System Impact Studies and Facility Studies for projects in the ISO queue. In particular, the utilities should describe each planned transmission upgrade and provide cost estimates. This will facilitate verification of bid adders for these projects, including any adjustments to provide deliverability, and will allow better understanding of other portions of the Transmission Ranking Cost Reports.
The ALJ ruling would require that each utility that was notified in its April 2, 2004 request for information that a project in its service territory is contemplating a bid to sell power to another entity should include in its Transmission Ranking Cost Report an estimate of transmission upgrade costs needed to deliver the power to the adjoining transmission system specified by the project developer. The ruling would require that a developer bidding to sell its power to another entity include with its bid an estimate of transmission upgrade costs needed to deliver the power to the purchasing utility. It specified that transmission costs to deliver the power to the purchasing utility, including wheeling costs in non-ISO control areas, would not be used in the first ranking of bids.
PG&E disagrees with the ALJ ruling regarding the treatment of wheeling costs in non-ISO control areas. Noting that the only available revenue stream for a generator to recover such costs is through the generator's contract with the utility, PG&E states that wheeling costs paid to non-ISO control areas should be internalized into the bid, similar to gen-tie costs, and should be considered in the first ranking of the bids. PG&E states that exclusion of wheeling charges from Supplemental Energy Payments can be facilitated by identifying such charges separately in the bid. PG&E agrees with the ALJ ruling that all transmission costs related to the ISO-controlled grid, whether incurred by the purchasing utility or by another utility whose system is traversed, should be used in the second ranking process.
In reply comments on the ALJ ruling, TURN agrees with PG&E that transmission wheeling costs incurred by out-of-state generators should be included in the bid price and included as part of the first ranking process. TURN takes issue, however, with PG&E's apparent view that Supplemental Energy Payments cannot be used to cover out-of-state transmission expenses. In TURN's opinion, § 399.15(a)(2) only prohibits the award of Supplemental Energy Payments for transmission upgrades made by a California electric utility.6
No party took issue with the method by which the ALJ ruling would require a subject utility would develop transmission costs for projects whose output may be sold to another utility. We agree that each utility that was notified in response to its April 2, 2004 request for information that a project in its service territory is contemplating a bid to sell power to another entity should include in its Transmission Ranking Cost Report an estimate of transmission upgrade costs needed to deliver the power to the adjoining transmission system specified by the project developer. The developer should then list that cost separately in its bid documentation.
We agree with PG&E regarding the treatment of wheeling costs in the bid ranking process. Because wheeling charges for the transport of power through non-ISO control areas are a cost to the developer, they should be included in the bid price so that the contractual revenue stream based on the bid price is sufficient to cover these costs. Because they are a cost to the developer, we see no reason why wheeling costs would not be eligible for Supplemental Energy Payments pursuant to § 399.15(a)(2). To aid in bid assessment, developers should list expected wheeling charges separately in their bids.
No party took issue with the provision in the ALJ ruling that transmission upgrade costs incurred if power traverses the network of a utility in the ISO-controlled grid should be used in the second ranking process. We agree that this approach is reasonable, but clarify the relevant language in Attachment A.
The ALJ ruling proposed that the utilities be required to file their Transmission Ranking Cost Reports within 14 days after Commission adoption of guidelines for preparation of the reports. SCE submits that 14 days is likely to be insufficient, even if utilities have all of the information needed from potential RPS generators well before a Commission order. SCE requests that each utility be given 21 days after it has received follow-up information from potential RPS generators or the Commission order, whichever is later. No party responded to SCE's request.
By previous ruling, the ALJ required that the utilities request no later than April 2, 2004 any additional information they may need from prospective RPS bidders, that interested developers respond within 15 calendar days, and that the utilities prepare additional conceptual transmission studies, if needed, based on the developers' responses. We expect that the utilities have complied with this ruling and have completed their conceptual studies. In today's decision, we reject several proposals that would have increased the effort required to estimate transmission costs, so that the adopted requirements for the Transmission Cost Ranking Reports are based largely on the completed conceptual studies. As a result, we believe that 14 days from the effective date of this order provides sufficient time for the utilities to prepare and file their Transmission Ranking Cost Reports.
In its comments, TURN notes that the ALJ ruling did not address the treatment of unanticipated renewable bids that the utilities did not consider in development of transmission cost estimates. TURN recommends that, if a utility receives a bid from a project that was not considered in the Transmission Ranking Cost Report and has not received System Impact and Facilities Studies, the bid still be eligible for consideration, with its treatment in the second ranking based on the utility's best estimate of potential transmission upgrades.
SDG&E replies that TURN's approach would provide bidders an incentive not to submit timely and sufficient information to the utilities for the preparation of transmission cost estimates. SDG&E recommends that, if the Commission adopts TURN's proposal, only bidders that were not on the utilities' distribution list for their April 2, 2004 request for information be allowed to bid in the absence of a previously determined transmission estimate applicable to their project.
PG&E agrees with TURN that, as a general principle, projects that were not studied prior to completion of the Transmission Ranking Cost Reports should be eligible for the RPS solicitation. Because the conceptual studies are based on project size and location, the Transmission Ranking Cost Report can be used to estimate transmission costs for any bidder that provides basic information regarding its project. PG&E is concerned, however, that it is not practicable to consider a bid that wishes to use an interconnection point that was not considered in the Transmission Ranking Cost Report. PG&E maintains that estimating transmission costs for a new project based on an interconnection point not available to other developers would be unfair to the other bidders, would introduce more disputes, and could delay RPS procurement. Therefore, PG&E recommends that bids be evaluated based only on interconnection points already analyzed in the Transmission Ranking Cost Report.
PG&E's suggested limitation on TURN's approach provides a proper balance that would further the goal of obtaining the least-cost, best-fit renewable resources while not introducing complications that could unnecessarily delay completion of the procurement process. We conclude that it is reasonable to allow developers to bid who have not previously notified the utilities of their existence, but that all bids should be limited to interconnection points analyzed in the Transmission Ranking Cost Reports.
Consideration of transmission costs in the rank ordering of RPS bids will entail an iterative process, as detailed in Attachment A. The ALJ ruling proposed that, within a geographic area, or "cluster," the utility would assign network upgrade costs to specific renewable bidders according to (1) their place in the ISO interconnection queue (for projects with completed System Impact Studies and Facilities Studies) or (2) their rank ordering without consideration of the purchasing utility's transmission upgrade costs. The utility would then undertake the least-cost second ranking of bids among all clusters, subject to best-fit considerations, to minimize total costs of power from RPS projects, including the cost of needed transmission upgrades.
In Section III.I of this order, we modify the proposal in the ALJ ruling regarding the treatment of transmission costs for delivering power from an out-of-area bidder to the purchasing utility. With the exception of that issue, no party took exception with the ALJ ruling regarding the iterative process for rank ordering RPS bids. With the adopted modifications, the rank ordering process in the ALJ ruling is reasonable.
The ALJ ruling described that the appropriate form of the transmission cost estimate used in assessing a bid, i.e., total cost, per-megawatt cost, or per-kilowatt-hour cost, may depend on the form of the bid. Each utility would be required to structure and apply transmission cost estimates in a manner that is consistent and transparent to the Commission when it reviews proposed RPS contracts. In its comments on the ALJ ruling, SCE states that the utilities should use an annual revenue requirement covering both capital expenses and operation and maintenance (O&M) costs, to reflect the total costs ratepayers will ultimately pay. SCE explains that O&M would include costs such as administrative and general costs, insurance, and property taxes. It also proposes that capital costs include the costs of financing during construction ("allowance for funds used during construction," or AFUDC) to determine the total rate base cost estimate. These costs would then be converted to a revenue requirement stream over the useful life of the asset.
As a general matter, it would be desirable to have consistent cost estimates for assessing RPS projects, regardless of whether the upgrades were identified through System Impact Studies and Facilities Studies or through the utilities' conceptual studies. However, costs have not been developed at the same level of detail or accuracy in the two types of studies. Additionally, we expect that AFUDC and O&M costs will be minimal, so that their inclusion or exclusion would be unlikely to change the relative position of RPS bids. We will allow, but not require, the utilities to modify the conceptual studies' cost estimates if the System Impact Studies and Facilities Studies contain AFUDC and/or O&M cost components that were not considered in the conceptual studies. If a utility makes such modifications, it should document the changes fully in its Transmission Ranking Cost Report, including a demonstration that these cost components were included in System Impact Studies and Facilities Studies and that consistent changes were made to the conceptual study cost results.
According to the ALJ ruling, the utilities would consider the entire cost of a transmission upgrade in ranking the projects that would use the upgrade. This approach is consistent with D.03-06-071, which provided that, at least in the near term, the full cost of network upgrades should be considered in application of the least-cost criterion. We will consider whether to refine this approach in later procurements.
We are concerned, in particular, that allocating the entire cost of a large transmission upgrade to the projects that have bid in response to one year's procurement solicitation does not take into account that, in some areas, the most cost-effective transmission upgrade may be large enough to accommodate more than one year's bidders. Considering the entire cost in assessing one year's bids may make it difficult for such projects to ever win the bid or for the needed transmission upgrade to be built.
During the PHC, an approach was discussed in which only a portion of the cost of a large transmission upgrade would be assessed in evaluating RPS bids if a threshold amount of projects have bid that would use the upgrade. The proposed decision issued on March 2, 2004 in the Tehachapi phase of this proceeding recommends that a study group examine the use of similar triggers for phased transmission upgrades in that region. Building on that concept, it may be desirable to reflect costs of a large transmission upgrade on a pro rata basis in the rank ordering of individual bids if a trigger mechanism has been adopted for construction of the transmission upgrade and sufficient bids have been received to initiate construction of the upgrade consistent with the trigger mechanism. We plan to explore whether these or other approaches could be adopted to improve the application of transmission cost adders in areas with large renewable resource potential.
Parties expressed concern at the PHC that sensitive information regarding renewable projects not be divulged. The ALJ ruling invited parties to address in their comments whether confidentiality requirements should be adopted. However, no party addressed this matter in its comments. As a result, we do not impose confidentiality requirements on any part of the adopted process for developing and considering transmission costs in the assessment of RPS bids.
In D.03-06-071, we provided that renewable developers will have the opportunity in this proceeding to dispute the results of transmission cost assessments.
In its PHC statement, CalWEA suggested an expedited dispute resolution mechanism or the dissemination of transmission cost information before Transmission Ranking Cost Reports are released as a means to speed evaluation of the utilities' transmission cost analyses. SDG&E suggested that a consultant be retained to resolve disputes.
The ALJ ruling did not recommend creation of a new dispute resolution mechanism and would instead allow parties to file comments on the utilities' Transmission Ranking Cost Reports. We adopt this process here, and provide that initial comments on the Transmission Ranking Cost Reports may be filed within seven days of the due date for the reports and reply comments may be filed within seven days thereafter. Consistent with the ALJ ruling, the Commission will then assess the adequacy of the reports on the basis of the filed comments and determine whether additional steps are warranted before the utilities' results are used in ranking bids for the initial RPS procurement. We delegate this responsibility to the Assigned Commissioner in this proceeding, so that the bid ranking process is not delayed by the time that would be necessary to bring disputes to the full Commission.
We also provided in D.03-06-071 that, following Procurement Review Group analysis, each utility should file an advice letter for Commission approval of its proposed contracts. PRG members and other parties will be allowed to raise transmission-related or other concerns in protests to those advice letters.
In its comments, TURN urges the Commission not to rely on protests from Procurement Review Group members as a method of handling disputes over transmission cost adders. TURN submits that it is unreasonable to expect non-market participants like TURN to independently review the transmission cost estimates for each bidder. TURN is also concerned that, once the utility has submitted contracts for approval, the Commission may be hard-pressed to deny the advice letters due to disputed calculations of the transmission cost adders. The opportunity for parties to file comments on the Transmission Ranking Cost Reports and for disputes to be resolved before the bids are evaluated should obviate much of TURN's concerns.
3 In FERC's Standard Large Generator Interconnection Agreement, Network Resource Interconnection Service would allow the generator to integrate its facility with the transmission provider's transmission system in a manner comparable to that in which the transmission provider integrates its own generating facilities to serve native load customers. Energy Resource Interconnection Service would allow the generator to use existing firm or non-firm capacity on the transmission provider's transmission system on an as-available basis. In essence, Network Resource energy would be fully deliverable, whereas Energy Resource energy would be curtailable when necessary to accommodate limitations on the transmission provider's system.4 Resource adequacy determinations are being made in R.01-10-024 and its successor rulemaking R.04-04-003. 5 The holders of Firm Transmission Rights or Congestion Revenue Rights would receive the revenue associated with transmission congestion. 6 As TURN notes, § 399.15(a)(2) provides as follows: "The Energy Commission shall provide supplemental energy payments from funds in the New Renewable Resources Account in the Renewable Resource Trust Fund to eligible renewable energy resources pursuant to Section 383.5, consistent with this article, for above-market costs. Indirect costs associated with the purchase of eligible renewable energy resources, such as imbalance energy charges, sale of excess energy, decreased generation from existing resources, or transmission upgrades shall not be eligible for supplemental energy payments, but shall be recoverable by an electrical corporation in rates, as authorized by the commission."