The second task before us is to adopt:
(B) A process that provides criteria for the rank ordering and selection of least-cost and best-fit renewable resources to comply with the annual California Renewables Portfolio Standard Program obligations on a total cost basis. This process shall consider estimates of indirect costs associated with needed transmission investments and ongoing utility expenses resulting from integrating and operating eligible renewable energy resources. (§ 399.14(a)(2)(B).)
Least cost and best fit are separate concepts, but pursuant to this statutory direction, we must consider the complex interrelationship between the two for purposes of implementing the RPS program. While least cost can be looked at in a relatively universal manner (once a calculation methodology is standardized), best fit is inextricably linked to the needs of a particular utility.
In that context the utilities should be considering the best fit that is available, which may or may not be a perfect (or even good) fit with their needs. As discussed in more detail below (under the heading "Flexible Rules for Compliance"), compliance with the procurement requirements of the statute is not excused just because a utility believes that the available renewable resources are not an ideal match with its own projected needs. With that caveat, we define best fit as being the renewable resources that best meet the utility's energy, capacity, ancillary service, and local reliability needs.
TURN and SDG&E, in their Joint Principles, identify two key concerns. First, the process should seek to balance bid prices with overall portfolio integration costs to ensure the lowest total ratepayer cost; and second, any preference for "best fit" resources should not be used to overly skew the selection process towards high-priced renewables. To the extent that the goals of the RPS program are dependent on PGC funds, procurement of too many high-priced resources could deplete those funds and frustrate the purpose of SB 1078. (Ex. RPS-25, p. 28.)
At the same time, ORA observes that the criteria we develop should take into consideration the fact that generation procured in the short-term (both renewable and non-renewable) should help contour utility portfolios to meet their load shapes in light of the continuing DWR contracts. Accordingly, for the short-term, renewable generation that can operate as dispatchable or peaker power may possibly fall slightly higher on the "procurement hierarchy."
According to ORA, however, over time these conditions will change, and in order to meet the goals of the RPS program (and the broader policy goal of diversifying the state's energy portfolio), the procurement hierarchy should be inverted, with increasing amounts of least cost renewable generation added to utilities' portfolios to meet the RPS goals, with new fossil fuel procurement helping to contour the renewable generation to the utilities' load shapes. (Ex. RPS-39, p. 15.)20 Over time, this should serve to address the ISO's concern regarding the relationship between procurement of new resources and over-generation.
The basic process to be used should be consistent with the general recommendations of CalWEA, that bids must be evaluated on a total cost basis, consistent with the statute, and that each utility should evaluate bids based on a consistent set of economic assumptions. (CalWEA Opening Brief, pp. 11-12.)
Consistent with § 399.14(a), each utility shall, on an annual basis, file a procurement plan stating:
(1) An assessment of its portfolio supply/demand balance to determine the optimal products sought in RPS procurement , including deliverability characteristics;
(2) Anticipated compliance flexibility mechanisms the utility may use, and current status of accrued deficits and surpluses;
(3) A bid solicitation for each product, with online dates and locational preferences; bidders can respond with products of their choosing, but the utility may prefer the products identified in their Commission-approved plan;
(4) Direction to respondent bidders to offer prices for 10-, 15-, and 20-year contract terms; and
(5) A list of factors the utility will consider as "tiebreakers," that bidders should enumerate and the Procurement Review Group (PRG) should consider when evaluating RPS procurement pursuant to the approved plan.
In light of the legislative direction to conduct RPS planning in conjunction with general procurement planning, we will coordinate with our general procurement proceeding in establishing the schedule for annual RPS plan filings.
The ranking process we adopt is iterative, as recommended by SCE and PG&E:
First Ranking: The purpose of the first ranking is to identify the bid price that will be compared with the market price referent.21 Bids are ranked according to the product-specific market price referent:
(1) The price referent reflects the value of two time-differentiated products, baseload and peaking. As RPS implementation continues to be developed, we will explore methods that more accurately reflect the value of energy and capacity on a time-differentiated basis. We will also examine methods of assessing a resource's ability to provide value to the utility on a time-differentiated basis, such as ELCC.
(2) For as-available bids, capacity values and allocation are set in advance by product and technology, subject to update in later phases of this proceeding and with reference to the ongoing CEC Integration Study, using:
a. Commission-approved capacity values, in $/kW-year, based on a combustion turbine, consistent with the standard method the Commission has used for Qualifying Facility (QF) capacity, as discussed by ORA and CalWEA. Use of other generation technologies for the capacity proxy will be considered in the upcoming Collaborative Staff and workshop processes described above in the discussion of Market Price Referents.
b. Commission-approved capacity allocation values currently in use for QFs, subject to update to more accurately reflect the capacity needs of the obligated utilities.
c. Capacity payments for as-available products are to be made in accordance with current Commission policy, to be reviewed in the next phase of this proceeding, and reflecting performance requirements.
(3) Alternatively, as-available bidders can elect not to use these Commission-established capacity values, and bid an all-in price to supply the baseload or peaking product.22
(4) Bidders of firm products will not have recourse to Commission-established capacity values, and will bid an all-in price to supply the baseload or peaking resource.
(5) All bids, regardless of whether they take advantage of Commission-established capacity values, are to be compared to the product-specific market price referent on an all-in basis.23
(6) Projects that already have preexisting SB 90 awards should not also be eligible for or receive SEPs. While it is difficult to fairly account for the SB 90 awards in the RPS process, projects with SB 90 awards may participate in the RPS solicitations to the extent that they are eligible and that they fulfill the solicitation requirements. When submitting bids in a solicitation, SB 90 award projects must declare that they possess an award, and choose whether they wish to relinquish their award prior to execution of a contract resulting from the solicitation. A bidder that chooses to relinquish its SB 90 award, and is otherwise eligible for SEPs, would be eligible for SEPs like other bidders. A project that chooses to keep its SB 90 award would be ineligible for SEPs. Similarly, projects receiving PGC funds from the Existing Renewable Facilities Program under section 383.5(c) would not qualify for SEPs. The choice must be made at the time of bid submittal, and will be applied whether the project would or would not receive SEP when its bid is compared to the appropriate market price referent. In either case, the utility should not add the expected or adjusted PGC amount to the project's bid when ranking the project.
Added consideration must be given to projects that are already on-line and have begun receiving payments from the CEC for their SB 90 award. If such a project is otherwise eligible for SEPs as determined by the CEC, then the bidder must also choose at the time of their bid submittal to either keep their SB 90 award or relinquish it if they are successful in the RPS solicitation, as described above. If the bidder chooses to relinquish their SB 90 award to compete for SEPs, and if they qualify for SEPs, then any PGC funding the project has received from its SB 90 award should be netted out of its SEP by the CEC. If a project is not among the winners in a solicitation, it is not required to relinquish its SB 90 award.
We recognize that the CEC will be establishing rules for eligibility and distribution of Supplemental Energy Payments from SB 1078 funds, and recommend that the CEC adopt requirements consistent with this decision.
Second Ranking: Bids are re-ordered based on integration and transmission costs
(1) CEC Integration Study working group methods are used to determine total integration costs for each short-listed contract;
a. The results of Phase 1 of the CEC integration study will reveal the integration impacts of present generation in specified areas. These results can act as a proxy for the integration effects of adding new resources in those same areas, if Phase 2 results are not available prior to the first RPS solicitation, as discussed in the TURN/SDG&E Joint Principles.
b. Results of Phase 2 of the CEC Integration Study will provide integration values for future resource additions at specific sites.24
c. Intermittent resources utilize the ISO's Amendment 42 and internalize costs into bids; no further utility calculation of schedule deviations is needed, as discussed in the TURN/SDG&E Joint Principles.
d. Remarketing costs are determined using the utilities' own power dispatch models, which are under consideration in the general procurement proceeding. Results and methods shall be made available to the PRG for complete review.
(2) Transmission costs will be assessed using the most appropriate process of those available, depending primarily upon whether the project is in the ISO development queue;25
a. Direct Assignment facilities are included the MPR, and therefore need to be included in the bid.
c. Otherwise, for bidders not in the ISO queue with completed cost estimates (i.e., the SIS and FS), PG&E proposes an annual transmission plan that is a workable alternative.28 PG&E's proposal is a reasonable starting point for the utilities to prepare their plans, although we do modify PG&E's proposal to improve its linkage with our Transmission OII (I.00-11-001).
d. Each proposed developer provides basic interconnection information to the transmission OII, to be defined in that proceeding.
e. Utilities develop a proxy bid price using approved methods, as described in PG&E's Transmission Least Cost and Best Fit Appendix A (Ex. RPS -7).29
i. Taking the interconnection information submitted by the bidder into the transmission OII, the utility will prepare an annual cost assessment plan to be made available at least 90 days prior to that year's RPS solicitation.
ii. In the transmission OII, each utility will specify what information it requires of developers to perform this assessment, and the OII will standardize the approach.30 The OII will also be the forum in which renewable developers will have the opportunity to dispute the results of these cost assessments.
The process described above will yield a workable approximation of the costs to the transmission system imposed by each new renewable generator. Several parties expressed concern that requiring an individual generator to finance the entire cost of a network upgrade will create a classic "free rider" problem-every developer will prefer to build the second facility in a new resource area, and take advantage of the investment made by a developer that is willing and able to finance the entire upgrade on their own. In this situation, potentially everyone waits, and no one builds.
While the up-front financing of substantial network facilities may pose a real burden to renewable developers, a true least-cost analysis must consider these costs as being triggered by the addition of particular renewable generators to the grid. At the same time, we recognize that the long-term goals of the RPS program may require a different approach to the financing of new network facilities.31 We will continue to explore this issue in conjunction with the ongoing Transmission OII.
Regardless of whether an individual generator, all potential generators, or some other entity pays the upfront cost of new network facilities, "least cost" requires that less-expensive generation options be pursued first. Incorporating new network facility costs in the rank-ordering of renewable bids will tend to favor generation with existing transmission facilities available.
In the near term, the likelihood that new renewable generation will require extensive network upgrades is lower than in later years of the RPS program, when the state will need to look farther afield to meet its goals. In later solicitations we hope to have a more articulated method of financing necessary network upgrades, but in the near term the full consideration of network facility costs called for here will yield the most favorable results for ratepayers.
As several parties note, it is conceivable that the addition of renewable generation to the grid may result in network benefits, and bidders are encouraged to describe any such potential benefits in their responses. Similarly, bidders should describe potential benefits of their projects to the considerations of local reliability, low income or minority communities, environmental stewardship, and resource diversity. The utilities should make it known in their annual plans that such benefits are sought, should apply transparent criteria in evaluating such claims, and should present the results of these evaluations to their PRGs for consideration.
Similarly, the utilities may favor curtailability and dispatchability as attributes of bids, but must make their analyses of these benefits clear for PRG and Commission review. As a general principle, we direct the utilities to continue to work cooperatively with their PRGs to develop a common understanding of the basis for evaluation and acceptance of RPS bids.
The following will illustrate the sequence of RPS plan filing, bid solicitation, market price referent development, bid evaluation, and PGC fund distribution:
As discussed above, the next phase of this proceeding will, with input from the parties, finalize the methodology for setting market price referents. The methodology will be established before RPS bidding commences; specific market price referents, however, will be uniquely generated for each solicitation, and will not be made known until bidding is closed.
When directed by the Commission, each utility will file an RPS procurement plan, soliciting products that will satisfy its Annual Procurement Target, which will be established in advance by the Commission. Each RPS plan will contain the proposed bid solicitation and ranking elements described above.
Up-front Commission approval of the plan will trigger the RPS bid solicitation, and at that time the Commission will initiate the process of developing market price referents for the full range of potential products. These products will initially be only two, baseload and peaking, but may expand following further Commission review of time-differentiation methodologies.
When the bid solicitation is issued, the Commission will make known the value of capacity to be assigned to as-available products, should developers choose to incorporate it into their bids.
If as-available bidders elect to use the Commission-approved capacity values for their product (either baseload or peaking), they will develop an energy price component for their product. As-available bidders utilizing Commission-approved capacity values must so indicate in their bid responses.
As-available bidders that choose not to incorporate these set capacity values, and instead offer an all-in price may do so, but utilities shall not discriminate against as-available bidders who elect to incorporate Commission-approved capacity values.
Firm bidders will determine for themselves the appropriate values of energy and capacity in their bids.
As-available bidders will be judged against either the baseload or peaker MPR, depending on the product that is bid.
After the closure of RPS bidding, the Commission will release the market price referents for the current-year solicitation.
Utilities will compare, on an all-in cost basis, the bids for baseload and peaking products from firm and as-available resources. This comparison will produce the first ranking of RPS bids.
A second ranking of bids will be conducted, incorporating estimates of integration and transmission costs, and reflecting the value of other benefits provided by a project, as described above.
This second ranking will determine the utility's proposed list of winning bidders. Selected bids should be sufficient to satisfy the utility's Annual Procurement Target, or the utility must follow the flexible compliance procedures outlined below in order to defer attainment of the APT.
Winning bids and all supporting analysis are then submitted to the utility's Procurement Review Group. Following PRG analysis and discussion, the utility will file an Advice Letter for approval of the proposed contracts. The PRG members will have an opportunity to make recommendations on the Advice Letter for Commission consideration.
Following Commission review and possible approval of the proposed contracts, the winning bids will be forwarded to the Energy Commission for consideration of Supplemental Energy Payment awards as needed.
To comply with the requirement in SB 1078 that Supplemental Energy Payments not be used to cover integration and transmission costs, the appropriate market price referent must be compared to the price revealed in the first ranking for each winning bid. Winning bidders that submit a price above the appropriate market price referent for their product must compete for subsidies under the SEP, in a manner to be determined by the Energy Commission.
Excess and insufficient procurement carries over to subsequent years in the manner described in the next section. Declines in the utility's baseline amount of renewable energy will trigger a commensurate procurement obligation, so that the steady progression towards 20% envisioned in SB 1078 is achieved.20 While we may wish to consider this issue further in future years, we do not want short-term procurement of best-fit renewable resources to be made at excessive cost, endangering the existence of longer-term renewable procurement. 21 If the CEC establishes caps on SEP payments, we may limit consideration of bids above the combined MPR and capped SEP.
22 The Commission will attempt to refine these capacity values to make them as accurate as possible, and utilities shall not discriminate against as-available bidders who elect to incorporate Commission-approved capacity values.23 A number of parties noted in comments that the Proposed Decision appeared inconsistent with the requirement of SB 1078 that bids be compared on an all-in basis. In fact, the Proposed Decision was consistent with the statute, but could have further clarified that if bids for identical products are being compared, and capacity values are fixed in advance, then an energy-only comparison is functionally identical to an all-in comparison. The energy prices in the bid and in the referent will increase by the same amount if pre-determined capacity values are added equally to each. 24 We are encouraged by the full participation this CEC process has enjoyed to date. 25 The below approach assumes the continuation of current FERC ratemaking practice. 26 CalWEA raises concerns regarding the allocation method (as opposed to the assessment method), which it argues could result in an excessive burden on one bidder, rather than proportionally to all potential bidders in a resource area. This problem is to be addressed in the Commission's OII process, and cannot be decided on the record in this proceeding. 27 There is general agreement that this is the ideal scenario for determining costs, but it is not always available. 28 PG&E calls this a "Transmission Ranking Cost Report." 29 PG&E's proposal is very detailed. While the following steps anticipate addressing it further in the current Transmission OII, parties should feel free to comment on other possible forums for addressing these issues. 30 Given the complexity of this analysis, we are not directing that a complete renewable transmission plan, such as that necessitated by SB 1038, be completed each year; rather we are seeking to standardize the basic steps the utilities and developers will take, as suggested by PG&E, to establish transmission cost estimates for particular projects. 31 One example would be to assign transmission costs according to the ratio of a project's MW output to the total potential MW of a particular resource area.