Least Cost and Best Fit

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 is 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.)¹⁵ 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: Bids are ranked according to the product-specific market price referent, adjusted for PGC fund awards:

(1) The price referent reflects the value of two time-differentiated products, baseload and peaking.

(2) Capacity values are set in advance by product, 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.




b. Commission-approved capacity allocation values currently in use for QFs.

(3) Capacity payments are made in two ways:

a. Firm: commitment by generator to supply, with damages for nonperformance.




b. Non-firm/Intermittent: paid for performance.

(4) The CT capacity value will be assessed in the same process in which the Commission establishes the baseload/peaker proxy using CCGT and CT.¹⁶

a. Capacity allocation values will be updated.




b. The entirety of this capacity payment method is subject to update pending the results of the current CEC Integration analysis.

(5) Bidders submit only an energy price; the capacity price is pre-determined; bids are ranked on energy only, as recommended by CalWEA and SCE.

(6) Consider PGC awards.¹⁷

Second Ranking: 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.¹⁸




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 flow models, which are under consideration in the general procurement proceeding. Results and methods shall be made available to the PRG for 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;¹⁹

a. Direct Assignment facilities are included the MPR, and therefore need to be included in the bid.




b. Network facilities:²⁰ For bidders already in the ISO Queue, the standard ISO System Integration Study (SIS) and Facility Study (FS) will yield sound estimates of network facility costs.²¹




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.²² 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).²³




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.

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 facilities²⁴. 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.