VI. Comments on the Draft Decision
Opening comments were filed by PG&E, SDG&E, SCE, ORA, CEERT, GPI, Calpine, and UCS. Reply comments were filed by PG&E, SDG&E, SCE, CalWEA, UCS, and TURN.16 We have reviewed the comments filed, and made changes to the Draft Decision as appropriate.
1. Pub. Util. Code §§ 399.14(a)(2)(B) requires the Commission to adopt a process and methodology for establishing a least-cost and best-fit evaluation criteria to be used in implementing the RPS program.
2. Commission D.03-06-071, as modified by D.03-12-065, began the process of developing the least-cost and best-fit criteria.
3. The Commission has considered the record in this proceeding and in the RPS phase of R.01-10-024, the previous procurement rulemaking.
4. The Commission and CEC Collaborative staff have held a workshop and received comments on the subject of least-cost and best-fit evaluation criteria.
5. It is reasonable to permit bidders to participate in more than one utility's RPS solicitation.
6. The utilities should issue RFOs for renewable generation resources consistent with the approved renewable procurement plans.
7. Pursuant to Pub. Util. Code § 399.14(a)(2)(A), Commission and collaborative staff should not participate in the procurement review groups until after the MPR has been disclosed. ORA may participate in the procurement review groups before the MPR is disclosed, as it is not part of the collaborative staff.
8. D.04-06-014 established a window from June 30, 2004 to July 15, 2004, during which utilities must issue Requests for Offers consistent with their approved renewable procurement plans.
9. It is reasonable to modify the adopted solicitation window to allow the utilities to revise their RFOs consistent with the orders adopted in today's decision.
10. It is premature to decide when the utilities should issue RFOs in 2005 and subsequent years.
11. It is reasonable to require bidders that have been "short-listed" to withdraw competing bids, to avoid the situation in which the utilities are negotiating against one another for the same project, potentially resulting in inflated prices.
12. Requiring bidders to withdraw competing offers after being notified that they are on a utility's short-list eliminates the need to require bidders to identify whether or not they have submitted multiple bids.
13. All bids should be treated as potentially multiple until the bids are short-listed and negotiations begin.
14. Given the fluid nature of the solicitation and contract approval process, it is not reasonable to adopt a rigid solicitation schedule.
15. The Integration Study finds that, at present levels of penetration, renewable generation causes no noticeable increase in the cost of ancillary services beyond those costs imposed by normal system variability.
16. The results of the Integration Study have been reviewed and affirmed by the California Energy Commission.
17. It is reasonable to use the results of the Integration Study for the 2004 RPS solicitation and adopt the Integration Study's findings of zero adders for regulation and load-following costs.
18. The CEC has statutory flexibility in administering the SEP funds, including establishing caps on the amounts any generator can receive.
19. For the initial RPS procurement, it is reasonable to allow the utility and the bidder to renegotiate the bid price or utility payment following the CEC's determination on any requested Supplemental Energy Payments to allow the utility and generator to structure payments under an RPS contract such that the contract provides appropriate performance incentives throughout the contract term.
20. The utilities should use their weighted average cost of capital (WACC) as the discount rate in calculating the level of utility payments over the first ten years that would result in total payments equal to the MPR over the life of the contract.
21. For wind resources, it is reasonable to adopt a capacity value that is an average of the capacity values found in the Integration Study for the existing resources in California's three principal wind areas (Altamont, San Gorgonio, and Tehachapi): 24%.
22. We do not adopt the Integration Study results for solar thermal electric resources, as these results were repudiated by the study's authors before adoption of the report.
23. Capacity values for solar thermal electric resources should be subject to negotiation between the bidder and the utility.
24. The Integration Study findings do not provide a capacity value for small hydro facilities.
25. Capacity values for small hydro should be subject to negotiation between the bidder and the utility.
26. The TURN proposal for "blending" the peaker and baseload MPRs is reasonable for use in the initial RPS solicitations, with the clarification that the Commission will identify the capacity factor used in calculating the peaking MPR and the utilities will have the discretion to allocate the number of hours inherent in this capacity factor to match their individual peak periods.
27. Utilities should treat curtailability, dispatchability, local reliability, and repowering as quantitative attributes.
28. All other potential benefits associated with renewable resources, such as benefits to low income or minority communities, environmental stewardship, local reliability, and resource diversity should be treated as qualitative attributes.
29. The presence of demonstrated qualitative attributes should be used to justify moving a bid onto the short list subject to two conditions: (1) the initial bid rank should be within reasonable price proximity to those selected for the short-list and (2) the utility should consult with, and receive support from, its PRG prior to elevating a bid based on qualitative factors.
30. The issue of debt equivalency is being considered in each utility's cost of capital proceeding.
31. SDG&E and SCE should use the average of the Integration Study's findings for wind, 24% as the minimum level of capacity credit to assign to wind facilities.
32. PG&E's time of delivery profile method provides an appropriate value for capacity independent of the Effective Load Carrying Capability calculations and is reasonable for use in the initial RPS solicitation.
33. Commission and CEC Collaborative staff should not participate in the PRG activities prior to the release of the MPR.
1. There is an adequate record in R.01-10-024 and in this proceeding to adopt criteria for the rank ordering and selection of least-cost, best-fit renewable resources.
2. The process adopted for the ranking of bids is consistent with the statutory requirements.
3. Pursuant to Rule 77.7(f)(9), we find that public necessity requires a reduction of the 30-day period for public review and comment on this draft decision because failure of the Commission to act on July 9, 2004, could endanger the public's health and welfare, and this clearly outweighs the public interest in allowing the full 30-day period for public review and comment.
4. Utilities should not add any ancillary service costs to the renewable energy bids they receive.
5. Allowing the utility and generator to structure payments under an RPS contract to ensure consistent performance incentives over the contract term is consistent with the intent of the RPS statute.
6. Utilities should apply a blended peaking and baseload MPR to products that do not fit squarely in either category.
7. The utilities should not use debt equivalency considerations in evaluating RPS bids at this time because the Commission has not approved a method for doing so, and debt equivalency analyses may discourage the long-term renewable energy contracts the Commission has indicated it favors.
8. With the requirement that SDG&E follow the direction provided above regarding integration costs, capacity values, and blended MPRs, SDG&E's proposed bid evaluation method is reasonable for use in the initial RPS solicitation and should be approved.
9. With the caveats regarding the linking of payments to bid profiles, the definition of peak, an the direction provided on integration costs and the blended MPR, as discussed above, PG&E's bid evaluation method is reasonable for use in the initial RPS solicitation and should be approved.
10. With the caveat that SCE should follow the capacity value guidelines provided above, and should provide its assumptions and results to its PRG for review, the proposed method for bid evaluation outlined by SCE is appropriate for this year's solicitation.
11. The utilities should issue RFOs for renewable generation resources consistent with today's decision and their approved renewable procurement plans.
12. In order to proceed expeditiously with RPS procurement, this order should be effective today.
IT IS ORDERED that:
1. A least-cost, best-fit methodology is adopted, as described above, consistent with the preceding Findings of Fact and Conclusions of Law.
2. The Assigned Commissioner and Assigned Administrative Law Judges will make such rulings as are necessary to effectuate this order.
3. The three major utilities have from July 9, 2004 to July 15, 2004 to issue their Requests for Offers for renewable generation resources, consistent with this order and their renewable procurement plans as approved by the Energy Division.
This order is effective today.
Dated July 8, 2004, at San Francisco, California.
MICHAEL R. PEEVEY
President
CARL W. WOOD
LORETTA M. LYNCH
GEOFFREY F. BROWN
SUSAN P. KENNEDY
Commissioners
