In this section, we address certain contested issues regarding development and use of transmission costs during the 2005 RPS procurement. Except to the extent modified by this order or by other Commission order, the utilities should continue to use the methodology adopted in D.04-06-013 for development and consideration of transmission costs during the 2005 RPS procurement.
At the workshop and in filed comments, parties debated the transmission costs that should be included in Transmission Ranking Cost Reports. Parties disagree regarding whether preferential treatment of renewable resources in the "loading order" adopted in the Energy Action Plan should be mirrored in the assessment of transmission costs used in RPS evaluations.
CEERT takes the position that no costs of transmission upgrades to relieve congestion on the interties should be assigned to RPS projects. In CEERT's view, the Transmission Ranking Cost Reports should reflect only those transmission upgrades identified through the CAISO interconnection process. CEERT maintains that congestion costs do not represent incremental system costs caused by the renewable project. It argues in addition that existing transmission users should not be grandfathered in dispatch assumptions used in the Transmission Ranking Cost Reports, since renewables will be allowed to compete for existing transmission capacity under the CAISO's open access policies. CEERT reports that a new proposed CAISO tariff, if approved by the Federal Energy Regulatory Commission (FERC), would auction off intertie capacity each day and that space on the intertie would go to resources willing to be paid the least amount for physical delivery. In CEERT's view, this dispatch procedure would favor renewables, in part because renewables typically have low variable costs.
CalWEA urges the Commission to direct SCE to assume that the network benefits associated with the Tehachapi upgrades that SCE calls Antelope Segment 1 (under consideration in Application (A.) 04-12-007) and Antelope Segment 2 (part of A.04-12-008) are at least equal to the costs of those upgrades. With that assumption, the transmission cost adders associated with those upgrades would be set equal to zero.
The utilities assert that the Transmission Ranking Cost Report methodology should mirror CAISO interconnection processes as closely as possible. In their view, the RPS transmission study results must be consistent with FERC interconnection processes and CAISO and utility interconnection tariffs in order to provide a reasonable proxy of transmission costs for bid ranking purposes. The utilities also maintain that any increases in congestion costs due to RPS projects should be recognized in the least-cost and best-fit analysis. They argue that the loading order in the Energy Action Plan relates only to the preferred order of resource procurement and has nothing to do with how the CAISO determines the network upgrades needed for interconnection of new generation to the grid. They point out, in addition, that the CAISO is bound by FERC's open access policies and is obligated to honor contractual rights of existing generators as it operates the transmission system. In their view, the Energy Action Plan loading order is irrelevant for the identification of transmission costs of RPS projects.
Our determination of what transmission costs should be included in consideration of RPS bids is based on the statutory requirements. Section 399.14(a)(2)(B) requires that the RPS rank ordering and selection process "consider estimates of indirect costs associated with needed transmission investments and ongoing utility expenses resulting from integrating and operating eligible renewable energy resources." This requirement, as part of the least-cost and best-fit selection mandate for RPS procurement, leads us to conclude that, as a general principle, the identification of transmission costs for use in the bid ranking process should reflect the actual net change in total transmission costs due to a project's interconnection and operation, to the extent practicable. Needed transmission upgrades and other transmission costs should be considered in evaluating an RPS bid, regardless of how the transmission system may be operated and transmission capacity allocated after an upgrade is built, and regardless of which entity funds transmission upgrades or incurs other changes in transmission costs due to the RPS project. Benefits derived from any needed transmission upgrades should also be considered. These principles guide us in assessing the parties' positions regarding the transmission costs to be used for bid ranking purposes.
We agree with the utilities that the CAISO System Impact Studies and Facility Studies, if they have been undertaken for a project, will provide valuable information in developing the Transmission Ranking Cost Reports and in bid evaluation. Such study results are likely to be a good starting point and, indeed, may be adequate in many cases. However, adjustment to CAISO study results for bid ranking purposes may be warranted, as contemplated in D.04-06-013, if interconnection and operation of the renewable project reduces transmission costs in other respects, to the extent such benefits may be quantified. Adjustments may also be appropriate if, for example, renewable generation is expected to replace planned non-renewable energy flows in a manner that reduces the need for transmission upgrades.3 We will revisit the continued reasonableness of the adopted Transmission Ranking Cost Report and bid evaluation methodologies in future years. We will continue to make improvements as appropriate and will continue to work with the CAISO toward this end.
As established in D.04-06-013, the utilities should consider any identified network benefits as offsets to needed transmission upgrade costs to the extent practicable. We note with interest the workshop presentation by the California Energy Commission's (CEC) Public Interest Energy Research (PIER) group describing its current efforts to identify locations where the addition of renewable resources would be beneficial to the transmission system. The CEC's PIER group posits that, at least in theory, addition of generation at identified spots could provide sufficient system benefits to outweigh the cost of network upgrades needed to interconnect the project. When available, PIER results may allow identification and quantification of network benefits of renewable projects and related transmission upgrades. As discussed in D.04-06-013, efforts initiated in this proceeding (and now being continued in I.05-06-041) to develop a generic methodology for assessment of the economic benefits of transmission projects may also be useful in this regard.
Contrary to implications by CalWEA, the recent determination by FERC that Segments 1 and 2 of the Antelope/Tehachapi upgrades should be classified as network facilities does not establish the level of network benefits that may occur due to these upgrades. Reliance on CalWEA's unsupported assumption that the network benefits of these upgrades equal their costs, so that the resulting transmission cost adder would be zero, would be discriminatory and could unfairly skew the bid evaluation process. We do not adopt CalWEA's proposal.
Consistent with the least-cost mandate in § 399.14(a)(2)(B), it is appropriate to consider the impact of RPS projects on the interties and other portions of the existing transmission system. If an RPS bidder proposes to locate and operate a project and sell its output in a manner that increases costs on an intertie, that increase in transmission costs should be considered when determining whether the project meets the least-cost requirement. To ignore those increased transmission costs would be detrimental to ratepayers and would be unfair to RPS bidders in other resource areas. As established in D.04-06-013 and as we discuss in the next subsection, project developers may propose curtailability or take other steps to reduce or avoid transmission costs in such circumstances.
Finally, we recognize that transmission upgrades related to RPS projects may provide system benefits other than transmission cost reductions, e.g., if an upgrade increases the transfer capability and allows a reduction in the cost of needed non-renewable energy purchases. We expect such beneficial results, if identified and quantified, to be incorporated into the least-cost and best-fit analysis of RPS projects, e.g., in integration and operating costs, as appropriate.
The staff's workshop report recommended that the Commission consider adopting a curtailability standard "on the order of 5-10%" as a means to further RPS goals while minimizing transmission expenses and limiting utility exposure to penalties for under-procurement. We do not adopt this proposal because there is not a sufficient record to establish that such a limit on allowable curtailability would be consistent with the least-cost and best-fit standard for RPS projects. We may revisit this issue in the future after additional experience with RPS procurement is gained.Consistent with the guidance in D.04-06-013 regarding curtailability proposals, it is reasonable to allow RPS bidders to structure their bids in other ways to reduce or eliminate the need for transmission upgrades, including proposals to use Remedial Action Schemes or other operational solutions. Like curtailability proposals, the viability of Remedial Action Schemes may be determined only after completion of detailed studies. In the preceding subsection, we establish that, in ranking and choosing among RPS bids, it is appropriate to consider the impacts of individual projects on the interties and on other portions of the transmission system. We recognize that, in circumstances with constrained interties, some RPS developers may prefer to forego both transmission upgrades and operational solutions such as Remedial Action Schemes if they believe that any increases in congestion costs due to their projects would be less than the costs of these alternatives. Since we are unaware of any current method to quantify expected congestion costs, we believe that this is an appropriate area of inquiry for our planned investigation of transmission issues related to renewables. We plan to include this topic in the OII. As SCE suggests, the costs of transmission upgrades may be used as a proxy for congestion costs in evaluating and ranking bids in the 2005 procurement. However, the parties may negotiate other estimates of congestion costs, as appropriate.
Through the use of dynamic line ratings, the conditions of transmission lines can be determined "in real time" and power flows can be managed in a more efficient manner. In D.04-06-013, we found it inappropriate to assume for purposes of evaluating the first RPS bids that the use of dynamic line ratings would reduce the need for transmission upgrades. We recognized, however, that dynamic line rating technology is evolving and we left open the possibility that future RPS bid evaluations may reasonably reflect the effect of dynamic line ratings.
The use of dynamic line ratings was discussed during the workshop. We remain unconvinced that this technology has advanced such that its use would allow transmission upgrades to be delayed or avoided. We will continue to monitor the development of dynamic line rating technologies.
In D.04-06-013, we noted CalWEA's position that the sizing of transmission facilities should take into account that maximum coincident generation from clusters of wind generation will be materially less than nameplate generation. We found insufficient information to determine whether or the manner in which the coincidence of wind generation should be reflected in planning transmission upgrades for wind generation.
At the workshop, parties reported that pending CEC-sponsored wind studies may provide useful information regarding the coincidence of wind generation. Such information may appropriately be reflected in future Transmission Ranking Cost Reports. If the utilities obtain information regarding the expected coincidence of wind generation--whether from CEC studies, RPS bids, or elsewhere-that is reliable enough to affect their transmission need determinations, they should incorporate such information in their Transmission Ranking Cost Reports and the bid ranking process. However, we continue to lack sufficiently reliable information to modify the Transmission Ranking Cost Report process at this time in this regard.
During the workshop, CEERT asked that the utilities be required to make carrying costs clear in their Transmission Ranking Cost Reports and also that the utilities be required to transform transmission costs into a cents-per-kilowatthour transmission cost adder. SCE responded that such calculations are performed only after bids are received.
As noted in D.04-06-013, the appropriate form of the transmission cost estimate used in assessing a bid, i.e., total cost, per-megawatt cost, or
per-kilowatthour cost, may depend on the form of the bid. The costs allocated to a particular project may also depend on whether other bids are accepted in the same area. As a result, development of a single per-kilowatthour transmission cost adder for an identified transmission upgrade is not appropriate. It is reasonable, however, to require that the utilities specify and explain the carrying costs, in addition to capital costs, of transmission upgrades identified in their Transmission Ranking Cost Reports. We adopt this requirement.
In D.03-06-071 and D.04-06-013, we provided that during their initial RPS procurement the utilities would consider the entire cost of a transmission upgrade in ranking the RPS projects that would use the upgrade. In D.04-06-013, we expressed concerns with this approach:
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. (D.04-06-013, mimeo. at 35-36.)
In D.04-06-010 issued contemporaneously with D.04-06-013, we instructed the Tehachapi study group to examine the use of triggers for the construction of phased transmission upgrades in that region. Recognizing the potential development of construction triggers, we stated in D.04-06-013 that:
[I]t 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. (Id., at 36.)
CEERT and CalWEA continue to assert that, for major renewables-related transmission expansions, transmission adders should be limited to each project's proportional share of the total upgrade cost based on project size compared to the capacity of the upgrade. We agree that waiting to adopt such an allocation mechanism until after a construction trigger has been adopted for a proposed transmission upgrade, as contemplated in D.04-06-013, could needlessly delay development of least-cost RPS projects. A more expedient approach, which we adopt, is to assign the costs of large transmission upgrades that would be used by more than one RPS project on a pro rata basis for purposes of bid evaluation, commencing with the 2005 procurement. This pro rata allocation of transmission upgrade costs for bid evaluation purposes should be based on generator output, as reflected in generation profiles submitted by the project proponent, compared to the transfer capacity that would be added by a proposed upgrade. As SCE suggests, this pro rata allocation of upgrade costs should be applied only if sufficient renewables potential exists, as identified by the CEC, to fully utilize the transmission facility sometime in the future.
In D.04-06-013, we adopted procedures whereby a utility would assign network upgrade costs to renewable bidders within a cluster (D.04-06-013, Attachment A, mimeo. at pp. A-9 and A-10). This same procedure should be followed to determine which group of RPS bidders should be assigned, on a pro rata basis, the lowest cost or higher cost transmission available in each cluster.
The allocation methodologies suggested by CalWEA and SCE in comments on the draft decision are too vague and ambiguous to be useful. The methodology we adopt is straightforward and can be implemented easily. It provides an estimate of transmission costs for each RPS project in a scenario in which the upgrade is fully loaded. As such, it provides a reasonable basis for evaluating individual RPS projects.
The first phases of transmission upgrades in the Tehachapi region are being considered in A.04-12-007 and A.04-12-008. As specified in the scoping memo for A.04-12-007, that proceeding will consider adoption of a trigger mechanism whereby approval or construction of each phase of the Tehachapi upgrades could be triggered. The approach we adopt today for the allocation of large upgrade costs for purposes of bid evaluation should be of great assistance in identifying viable wind projects in the Tehachapi region and in determining whether, or when, sufficient wind projects meet least-cost and best-fit criteria to warrant construction of Tehachapi upgrades.
SCE raises a concern that a pro rata transmission cost allocation for bid evaluation purposes before a sufficient amount of megawatts is bid to justify construction of the transmission upgrade could create the potential for "stranded" contracts that may never materialize if transmission construction is not justified subsequently. We are aware of this possibility, but remain convinced that the adopted allocation method is the best approach for ascertaining the viability of RPS projects in these areas.
Most, if not all, generation projects submitted in response to a utility procurement have some level of uncertainty regarding whether they actually will be built as proposed. RPS projects that are dependent on transmission upgrades are no exception. The utilities should take into account potential uncertainties associated with each RPS project as they decide how many projects to pursue to ensure compliance with the State's RPS goals. In order to avoid potential adverse financial consequences, it is reasonable for contracts for RPS projects to specify that the utility's financial obligations to purchase project output are contingent upon construction of any transmission upgrades that are identified as needed when the contract is signed.
In comments on the draft decision, CalWEA brings a concern to our attention that has not been addressed previously. CalWEA recommends that the three utilities share sufficient information about the bids they receive so that they have full knowledge about the total amount of capacity that has been bid from within a particular cluster. CalWEA raises this concern in the context of its proposal that the cost of a large transmission upgrade be allocated among the renewable resources that would use that upgrade. However, the concern exists whether or not the pro rata allocation methodology adopted in the preceding subsection is appropriate for a given cluster of projects.
We agree that, in situations where there are RPS bids to more than one utility for RPS projects within the same cluster, the utilities may need to share limited information about the bids in order to properly assess transmission costs. Therefore, it is reasonable to allow the utilities to share limited information in this situation. In D.04-06-013, we chose not to impose confidentiality requirements on the adopted process for developing and considering transmission costs in the assessment of RPS bids. However, we realize that the need to share bid information, even on an aggregated and limited basis, may raise potential confidentiality and competitive concerns. For this reason, the utilities should share no more information than needed to identify the total capacity of bids submitted within a cluster and to assess how to allocate the cost of any proposed transmission upgrades to those bids.
The procedures adopted in D.04-06-013 for prioritization and allocation of phased transmission upgrades did not contemplate that bids for projects within a cluster may be submitted to more than one utility. The record is insufficient to resolve how an allocation of upgrade costs should be handled if bids submitted to more than one utility exceed the capacity of the lowest cost upgrade available. We plan to address this issue in the investigation into transmission issues related to renewables that we plan to issue in the near future. If, after sharing narrowly focused information regarding bids received in response to the 2005 RPS procurement, the utilities determine that they need guidance on this issue in order to evaluate the 2005 bids, the utilities should inform us immediately so that this matter can be addressed expeditiously. We plan to establish procedures in the OII to address this contingency.3 In its interconnection studies, which are project-specific, the CAISO assumes that existing generation within the local area of study will continue to operate as planned and that operation of the new project under consideration will increase transmission loadings as a result. The CAISO assumes that the proposed project will displace output from generation located away from the local area. While this conservative assumption may provide a reasonable approximation of transmission upgrades needed for a single new project, with the cumulative addition of enough renewable projects to meet RPS goals, this approach may identify a need for transmission upgrades incorrectly in some instances.