Comments on Draft Decision
The draft decision of the ALJ in this matter was mailed to the parties in accordance with Section 311(d) of the Public Utilities Code and Rule 77.7 of the Rules of Practice and Procedure. Comments were filed on , and reply comments were filed on .
1. PURPA obligates utilities to purchase QF power.
2. During the period November 1998 through December 1999 the Section 390(b) price consistently exceeded the PX market clearing price.
3. The QFs-In/QFs-Out methodology proposed by CAC and IEP results in payments to QFs that exceed the PX day-ahead clearing price.
4. The new entrant proposals of SCE and ORA result in payments to QFs below the PX day-ahead clearing price.
5. Adoption of the PX day-ahead price in 1999 would have resulted in lower QF energy prices, as compared to the Section 390(b) formula, for SCE and SDG&E.
6. Adoption of the PX day-ahead price in 1999 would have resulted in higher QF energy prices, as compared to the Section 390(b) formula, for PG&E.
7. Wind and run-of-river resources cannot control the timing of their generation output.
8. Wind and run-of-river hydro resources do not produce NOx, SOx, or particulates.
9. An hourly pricing mechanism would disadvantage intermittent resources.
10. From December 1998--November 1999, adopting a monthly weighted-average PX price for wind and run-of-river hydro resources would have cost an additional $9.6 million compared to paying an hourly PX price.
11. The new entrant proposals are not based on the marginal generating unit but on a hypothetical new entrant.
12. The new entrant proposals are only marginally linked to the PX price.
13. The new entrant and heat rate cap/dollar proposals rely on administratively determined assumptions to operate.
14. More than 90% of utility energy purchases have been made from the PX day-ahead market since the market opened.
15. The PX day-ahead market clearing price has routinely exceeded conservative administrative estimates of energy costs.
16. The PX day-ahead market clearing price includes non-energy value.
17. The value of capacity as defined in Section 390(d) has, at all times, yielded a value of zero and is unlikely to yield any other value.
18. The PX price represents an "all-in" energy and capacity price for must take resources for which energy production is delivered exclusively to the PX marked.
19. The PX day-ahead price, adjusted by the Section 390(d) capacity subtracter, reflects some capacity value.
20. The ISO's spinning reserve and non-spinning reserve markets are capacity reserve markets.
21. The ISO's spinning reserve and non-spinning reserve prices reflect the addition of an added increment of production on reserve margins and reliability.
22. Adoption of a 50/50 weighting of ISO spinning reserve and non-spinning reserve price as the capacity subtracter would have resulted in an energy price 12 to 59% lower than the PX day-ahead price over the comparison period.
23. There are a number of valid ways to allocate system line losses.
24. No remote QF solely serving local load was identified.
25. CCC's bifurcated line losses methodology maximizes QF SRAC payments.
26. The GMM methodology may be revised from time to time by FERC.
27. The PX clearing price reflects the system average GMM.
28. For a QF paid under the Section 390(b) transition formula, the GMM must be adjusted by the system average GMM.
29. Even if large amounts of energy are purchased outside of the PX day-ahead market, the PX day-ahead price may still represent a reasonable approximation of utility avoided cost.
1. CCC's June 14, 2000 Motion to Set Aside Submission should be granted.
2. Appendix A to CCC's June 14 Motion should be marked as Exhibit 29 and received into evidence as of June 14, 2000.
3. SCE's June 14, 2000 Motion to Strike should be denied.
4. CCC's June 21, 2000 Motion to Strike should be denied.
5. QF pricing must comply with both the requirements of PURPA and the Public Utilities Code.
6. Payments to QFs must reflect the full avoided cost of the utility purchasing the QF power.
7. Adoption of a monthly weighted-average PX-based price complies with PURPA.
8. Section 390(c) requires that SRAC energy payments be based upon the PX clearing price.
9. The proposal to use the day-ahead PX clearing price for QF energy payments complies with Section 390(c).
10. Because the utilities are required to buy the majority of their electricity from the PX, the PX day-ahead clearing price is a reasonable measure for utility avoided cost.
11. The PX zonal day-ahead clearing price (adjusted consistent with Section 390(d)) should be adopted as the QF SRAC energy price.
12. The societal benefits associated with resource diversity and environmentally preferred energy production by wind and run-of-river hydro QFs outweighs the ratepayer cost of FPL's proposal.
13. Wind and run-of-river hydro QFs should be allowed to elect, at their option, to receive a monthly weighted-average PX day-ahead price (adjusted consistent with Section 390(d).
14. The Commission must comply with Section 390(d), even if it believes such law conflicts with PURPA.
15. Section 390(d) defines the value of capacity for purposes of calculating SRAC payments to QFs.
16. As-available capacity payments should be eliminated.
17. The 50/50 weighting of ISO spinning reserve and non-spinning reserve prices is a reasonable measure of capacity value.
18. Using GMMs is one reasonable way to allocate system line losses.
19. Proposals to modify the GMM methodology should be directed to FERC.
20. The Commission should adopt the GMM of each QF as its transmission loss factor once QFs are paid a PX-based energy price.
21. Until QFs are paid a PX-based energy price, the transmission loss factor should be GMM QF/GMM SYS.
22. QFs who have elected to switch to a PX-based SRAC should have the GMM of each QF applied as its transmission loss factor, effective immediately.
23. We should adopt distribution loss factors based on the WDAT for SDG&E and SCE and of 1.000 for PG&E which will be multiplied by the TLF to arrive at the total loss factor for distribution level QFs.
24. In order to determine that the PX is functioning properly under Section 390(c), the PX day-ahead market must provide an ongoing market clearing price, and the PX day-ahead market must be the market where utilities procure the majority of energy for their customers, and the PX day-ahead market must reasonably represent the costs of other utility purchases. If the PX is that market, then it represents the utilities' avoided cost, and it is functioning properly for purposes of QF payments.
25. Parties should address posting procedures in Phase 2.
26. Parties should be prepared to address any required revisions to accounting procedures at the Phase 2 prehearing conference.
27. Implementation costs should be evaluated for reasonableness along with other QF contract administration issues in the Annual Transition Cost Proceeding.
28. No true-up for QFs paid subject to D.99-11-025 is required.
29. This decision applies to all respondent utilities.
IT IS ORDERED that:
1. In Phase 2, the Commission shall determine whether the requirements of Pub. Util. Code § 390(c), as further set forth in Conclusion of Law 24, have been met. The assigned Administrative Law Judge shall convene a prehearing conference within 45 days of the effective date of this order to establish a schedule for Phase 2.
2. Upon the Commission making appropriate findings in Phase 2, qualifying facilities receiving firm capacity payments, forecast as-available capacity payments, or forecast as-delivered capacity payments from respondent utilities shall be paid the Power Exchange (PX) zonal day-ahead clearing price (adjusted consistent with Section 390(d) as set forth in Conclusion of Law 15) as the short-run avoided cost (SRAC) of energy.
3. Upon the Commission making appropriate findings in Phase 2, wind and run-of-river hydro qualifying facilities may elect, at their option, to receive a monthly weighted-average PX day-ahead price (adjusted consistent with Section 390(d)) in lieu of hourly pricing once the Commission has made the required findings under Section 390(c).
4. Upon the Commission making appropriate findings in Phase 2, qualifying facilities receiving as-available capacity payments from respondent utilities shall be paid the PX zonal day-ahead clearing price as the total SRAC of energy. As-available capacity payments shall be eliminated.
5. Once qualifying facilities are paid a PX-based energy price, the Generation Meter Multiplier (GMM) of each qualifying facility shall be applied as its transmission loss factor.
6. Effective with the first posting following this decision, the transmission loss factor shall be GMM QF/GMM SYS.
7. Qualifying facilities who have elected to switch to a PX-based price shall have its GMM applied as its transmission loss factor, effective immediately.
8. Effective with the first posting following this decision, distribution loss factors shall be based on the Wholesale Distribution Access Tariff for San Diego Gas & Electric Company and Southern California Edison Company and shall be 1.000 for Pacific Gas and Electric Company. The distribution loss factor shall be multiplied by the adopted transmission loss factor to arrive at the total loss factor for qualifying facilities connected at the distribution level.
This order is effective immediately.
Dated , at San Francisco, California.
APPENDIX A
List of Appearances
************ APPEARANCES ************ |
Lindsey How-Downing |
Edward W. O'Neill |
Julio Ramos |
Michel Peter Florio |
Michelle Cooke |
Edward G. Cazalet |
James L. Mcarthur |
Richard J. Mc Cann |
(END OF APPENDIX A)
