13. IOU Motions
On June 5, 2007, PG&E, SCE and SDG&E jointly filed Motion to Strike Appendices to Opening and Reply Comments of the California Cogeneration Council and to the Reply Comments of the Cogeneration Association of California and the Energy Producers and Users Coalition (Motion to Strike). Along with the Motion to Strike there was a Motion to Shorten Time to Respond to Motion to Strike and to Shorten Time for Responses to this Motion (Motion to Shorten Time).
In the Motion to Strike, the IOUs contend that both CCC and CAC/EPUC included appendices which contained new analysis that was not part of the record of this proceeding. Further, the IOUs assert that the appendices violated the page length limits established by ALJ Cooke. Accordingly, the IOUs request that the following appendices be stricken:
1. Comments of the California Cogeneration Council on the Proposed Decision of ALJ Halligan, dated May 25, 2007, Appendices B and C.
2. Amended Comments of the California Cogeneration Council on the Proposed Decision of ALJ Halligan, dated May 31, 2007, Appendices B and C.
3. Reply Comments of the California Cogeneration Council on the Proposed Decision of ALJ Halligan, filed June 4, 2007, Appendices A and B.
4. Reply Comments of the Cogeneration Association of California and the Energy Producers and Users Coalition (CAC/EPUC) filed June 4, 2007, Table 1 and Attachments B and C.115
In its opposition to the Motion to Strike, CCC first argues that the appendices at issue were summaries of the CCC's proposals, charts containing publicly available data or excerpts of Commission decisions. (CCC Opposition, pp. 5 & 7.) CAC/EPUC similarly argue that their appendices are consistent with the record of the proceeding or based on public information. Both CCC and CAC/EPUC further note that they had included the appendices for the Commission's convenience.
We agree with CCC and CAC/EPUC that the appendices at issue contain information that is either publicly available or part of the record of this proceeding. Therefore, they could be included and considered by the Commission. However, we agree with the IOUs that inclusion of these appendices resulted in CCC and CAC/EPUC exceeding the page limits established by the ALJ.
Rule 14.3 of the Commission's Rules of Practice and Procedure establishes the applicable page limits for comments and replies. Rule 14.3(b) further notes: "Comments shall include a subject index listing the recommended changes to the proposed or alternate decision, a table of authorities and an appendix setting forth proposed findings of fact and conclusions of law. The subject index, table of authorities, and appendix do not count against the page limit."116 With the exception of this exclusion, the page limits established in Rule 14.3 apply to the entire document, not just the text of the comments and replies. Accordingly, with the exception of those items specified in Rule 14.3(b), all other appendices or attachments would be included in the page count.
Parties are required to comply with the page limits established in the Commission's Rules. Indeed, the language in Rule 14.3 specifically uses the word "shall" with respect to the page limits. In this instance, ALJ Cooke had extended the page limits for both comments and replies beyond the limit specified in Rule 14.3. As the IOUs noted, if CCC or CAC/EPUC had felt that the page limits should be extended even more, they should have made such a request to ALJ Cooke. In light of these considerations, we find that CCC and CAC/EPUC violated the extended page limits by not including the appendices at issue as part of their page count. Accordingly, we grant the IOU's Motion to Strike.
We deny the IOU's Motion to Shorten Time. This motion was premised on the anticipation that the Commission would be voting on the proposed decision before responses to the Motion to Strike had been filed. However, the proposed decision was held so that the Commission could hold a final oral argument, as requested by CCC in its Opening Comments. Since the basis for shortening the time to respond to the Motion to Strike was no longer present, the IOU's Motion to Shorten Time is denied.
1. PURPA requires electric utilities to purchase electricity from QFs.
2. QF pricing must comply with both the requirements of PURPA and the Public Utilities Code.
3. Pub. Util. Code § 390 provides an interim formula for calculating short-run avoided cost energy payments to QFs.
4. Current short-run avoided cost postings are based on the Transition Formulas adopted in D.96-12-028 as modified by D.01-03-067, which incorporate various California natural gas border price indices.
5. The Transition Formula can be updated periodically.
6. Power is traded on a Day-Ahead basis at various trading points (a.k.a., hubs or markets) throughout the country, the West, and in California, including North-of-Path 15 (NP15) and South-of-Path 15 (SP15).
7. Bilateral power traded at the NP15 and SP15 trading points are voluntarily reported through a number of indices, including indices published by Dow Jones and Platts. Power traded through the ICE is actually brokered through the exchange as a commodity.
8. It is neither reasonable nor practical to base short-run avoided costs on a "QF-out" or "aggregate value" pricing methodology because the continuing long-term obligations to thousands of megawatts of QF power mean that QF power cannot be "out."
9. The Transition Formula was intended as a temporary measure, to be used to calculate SRAC energy payments until energy payments could be based on PX market-clearing prices pursuant to § 390(c).
10. The PX is no longer operational.
11. SRAC energy payments under the Transition Formula have exceeded market prices, and potentially avoided costs, on occasion.
12. Given the amount of QF generation currently under contract to the IOUs, an energy price that is based on an assumption that a large block of that generation has disappeared is not reasonable.
13. Each of the utilities has demonstrated that market prices play a key role in achieving least cost dispatch.
14. The NP 15/SP 15 markets include less than 5% of the utility power purchases.
15. The state still relies on out-of-market transactions, like reliability must run contracts, and must offer obligations to fulfill some of its energy and capacity needs.
16. In determining the need for reliability must run contracts the CAISO assumes that all must-take resources, including QFs are operating.
17. The market price of energy at the NP15/SP15 trading points does not reflect the costs associated with out-of-market transactions entered into by the CAISO for market power mitigation and local reliability purposes.
18. Generators that operate pursuant to Reliability Must Run and Must Offer Obligations tend to be less efficient/higher heat rate units than those that would be dispatched under normal or unconstrained operating conditions.
19. Through their role as scheduling coordinators, the utilities could influence the market clearing price at the NP15/SP15 trading points.
20. Until MRTU is operational, SRAC energy prices should incorporate power prices as reported at the NP15 trading point for PG&E, and at the SP15 trading point for SCE and SDG&E.
21. Once MRTU is operational, MRTU day-ahead market clearing prices will provide more robust day-ahead market prices that would more accurately reflect avoided costs.
22. PG&E's energy pricing proposal links the SRAC energy prices to day-ahead trading points, but would require formal Commission updates immediately and on an ongoing basis.
23. A Market Index Formula based on an average of forward NP 15/SP 15 market prices and the existing Commission adopted heat rates reasonably reflects the utilities' short-run avoided cost.
24. It is reasonable to use forward, rather than historical prices to develop the market heat rate component of the Market Index Formula.
25. It is unreasonable to use CCC's proposed elasticity adder.
26. There is no compelling reason not to adopt the same variable O&M adder for all three utilities.
27. With regard to avoided cost, whether the utility bought the gas to run its own plant, or bought the power from a merchant plant fueled by natural gas, burner-tip gas would be required.
28. The Legislature did not adopt a specific formula or specific factors for use in implementing § 390(b).
29. The Commission should update the TOU factors used to calculate SRAC in an appropriate proceeding.
30. Pursuant to D.04-10-035, QF as-available capacity currently "counts" for purposes of meeting RA requirements.
31. The firmness of bilateral power may vary by trade, whereas the power products traded on ICE are clearly defined. Power contracts traded on ICE are liquidated damages contracts that are not unit contingent.
32. Power indices are also published for the long-term forward market where power is sold by the month, quarter, and year. These forward prices, along with day-ahead power, represent firm power products priced on an all-in basis, with no separate capacity payment. Delivery is certain and subject to recourse.
33. NP15/SP15 day-ahead contracts are significantly firmer than QF as-available power contracts which have no penalties for non-delivery, no forecasting requirements, no performance requirements, and a unilateral right to terminate on 30-days notice.
34. Using a levelized nominal dollar value to compute the CT cost would overstate the avoided capacity cost as well as present additional cost and risk for utilities and ratepayers.
35. Using an economic carrying charge rate, escalated for inflation over the life of the contract, allows us to provide more flexibility in contract terms, from one year up to ten years with the same CT cost estimate.
36. For purposes of calculating payments for as-available capacity, it is reasonable to adopt the CT cost and real economic carrying charge rate calculations proposed by TURN as presented in Exhibit 149, Appendix B, with an ancillary services adjustment and an energy benefit adjustment subtracted from the adopted value as suggested by SDG&E and TURN.
37. As-available and firm capacity payments should be reduced to reflect the energy benefits adjustment proposed by SCE.
38. A simplified version of the Edison Electric Institute Master Agreement will be the basis for our prospective QF Program contract options. The simplified version should contain, at a minimum, the contract features presented in Table 1 of this decision.
39. The IOU may only deny a prospective contract if it will result in over-subscription and after if meets and confers with its Procurement Review Group. If the IOU does not enter into a contract with the new QF, the new QF may opt to file a formal compliant with the Commission.
40. Small QFs cannot bid into utility RFOs or sell surplus power directly to the CAISO.
41. It is consistent with Commission policy for Combined Heat and Power to allow new, small QFs to obtain standard contracts.
42. It is reasonable to establish specific provisions in this decision that limit the ability of the IOUs to deny a contract to small QFs on the basis of oversubscription.
43. For purposes of this decision, it is reasonable to define small QFs as QFs under 20 MW, or that offer equivalent annual energy deliveries of 131,400 MWh, and that consume at least 25% of the power internally and sell 100% of the surplus to the utilities. This definition includes any new increments of capacity added to the project.
44. Long-term QF policy choices will continue to affect ratepayers for 10 to 20 years.
45. It is reasonable to extend our prospective QF Program contract options to QFs that are, or were, on contract extensions approved in D.02-08-071, D.03-12-062, D.04-01-050, and D.05-12-009.
46. It is reasonable to allows QFs with expiring contracts to extend the non-price terms of their agreements and continue to provide service under the pricing set forth in this decision until such time as the prospective QF Program contracts options are available.
47. A technical workshop should be held within 60 after the effective date of this decision to address issues associated with the implementation of the QF program.
1. Pursuant to Pub. Util. Code § 390(b), SRAC energy payments shall be based on a Transition Formula until the requirements of § 390(c) are met.
2. As set forth in PURPA, avoided costs are the cost of energy, which, in the absence of QF generation, the utility would otherwise generate itself or purchase from another source.
3. No right, contract term, or fair market expectation exists that the Commission must adopt the QF-in/QF-out approach to developing short-run avoided costs.
4. The variable factor formulation of the Transition Formula, as established in D.01-03-067, and updates to the formula are legal and permitted by § 390(b).
5. The Commission should adjust the factors in the Transition Formula such that the SRAC energy prices resulting from the formula continue to accurately reflect the utilities' avoided costs.
6. Once MRTU is fully operational, the Commission should adjust the Market Index Formula to take advantage of the energy market information revealed by the existence of MRTU day ahead market prices.
7. Changes to the Market Index Formula methodology should apply to the going forward SRAC energy prices paid under all contracts, both existing and new.
8. A decision to revise the Transition Formula, by itself, does not demonstrate that prices under the Transition Formula violate PURPA.
9. The Market Index Formula complies with PU Code § 390(b).
10. Separate capacity payments should generally only be made for unit-contingent power products that are either dispatchable, or that are significantly firmer than the non-unit contingent, Liquidated Damages contracts (i) bought and sold at NP15/SP15, and/or (ii) scheduled for phase-out for Resource Adequacy purposes, per D.06-10-035.
11. The Unit-Firm one- to ten-year QF contracts should count toward RA requirements because these contracts are unit-contingent contracts with performance obligations and recourse for non-delivery.
12. Payments to QFs under PURPA must reflect the avoided cost of the utility purchasing the energy and capacity.
13. Failure to consider utility resource needs in our long-term QF policy options would prevent us from achieving our goal of environmentally-sensitive, least-cost electric service.
14. IOUs should modify their monthly SRAC energy prices using the Market Index Formula adopted in this order.
15. IOUs should post the monthly SRAC energy prices and annual capacity prices on their websites and file the prices with the Commission's Energy Division and DRA.
16. PURPA does not require that the Commission make available long-term standard offer contracts.
17. A solicitation process wherein the IOUs would issue requests for offers from QF generators to meet specific, identified resource needs, is sufficient to meet the must purchase obligations in PURPA.
18. Potential over-subscription due to new QF contracts, that are not covered by the small QF contract exemption described below should be evaluated, first, through and IOU's long term procurement plan. Second, the IOU's Procurement Review Group should review proposed contracts for new QFs within 20 days of receiving such a request from a new QF. If the IOU does not enter into a contract with the new QF, the new QF may opt to file a formal compliant with the Commission.
19. For small QFs , the IOUs may not deny one of the two contracting options described herein on the basis of oversubscription unless the total capacity of QF power would, with the proposed contract, exceed 110% of the utilities QF capacity as of the date of this decision.
20. The prospective QF Program contract options should be extended to existing QFs as well as QFs that are, or were, on contract extensions set forth in D.02-08-071, D.03-12-062, D.04-01-050, and D.05-12-009.
IT IS ORDERED that:
1. Pacific Gas and Electric Company (PG&E), San Diego Gas & Electric Company (SDG&E), and Southern California Edison Company (SCE) shall revise their QF programs, including the short-run avoided cost (SRAC) calculations and the implementation of their Prospective QF program, in conformance with the discussion, findings, and conclusions set forth in this decision as summarized in Table 1.
2. Energy Division shall hold a technical workshop within 60 days of the effective date of this decision. Parties shall create a list of the relevant issues and recommend proposals for resolving them for discussion at the workshop and submit to Energy Division within 30 days of the effective date of this decision. Further, the workshop will consider the draft contract proposed by EPUC/CAC in their Opening Comments on the Alternative Proposed Decision of Commissioner Grueneich, filed on September 10, 2007. The respondent IOUs shall comment on the EPUC/CAC draft contract and present at this workshop their draft standard offer contracts.
3. PG&E, SCE, and SDG&E shall file a joint Tier 3 advice letter implementing the Market Index Formula, and specifying the data sets and formula used to calculate the Market Index Formula 30 days after the workshop mentioned in OP2. PG&E, SCE, and SDG&E shall each file a Tier 3 advice letter with standard offer contracts within 60 days of the workshop.
4. The assigned Commissioner has authority to delay the implementation of the revised MIF if they determine that the market component of the MIF will not reflect the heat rate component of avoided costs.
5. The Motion to Strike Appendices to Opening and Reply Comments of the California Cogeneration Council and to the Reply Comments of the Cogeneration Association of California and the Energy Producers and Users Coalition filed jointly by PG&E, SCE and SDG&E is granted. The following appendices are stricken.
6. Comments of the California Cogeneration Council on the Proposed Decision of ALJ Halligan, dated May 25, 2007, Appendices B and C.
7. Amended Comments of the California Cogeneration Council on the Proposed Decision of ALJ Halligan, dated May 31, 2007, Appendices B and C.
8. Reply Comments of the California Cogeneration Council on the Proposed Decision of ALJ Halligan, filed June 4, 2007, Appendices A and B.
9. Reply Comments of the Cogeneration Association of California and the Energy Producers and Users Coalition (CAC/EPUC) filed June 4, 2007, Table 1 and Attachments B and C.
10. PG&E, SCE and SDG&E's Motion to Shorten Time to Respond to Motion to Strike and to Shorten Time for Responses to this Motion is denied.
11. Rulemaking (R.) 04-04-003 and R.04-04-25 are closed. Filings from the Mohave Application, (A.) 02-05-046 ordered by D.04-12-016 to be filed in these proceedings are no longer to be filed. Instead, D.04-12-016 compliance reports are to be submitted to the ALJ and Energy Division and served on the service list for A.02-05-046. The service list for A.02-05-046 will now be a special service list in R.06-02-013. Filings from the 2006 Update phase of R.04-04-025 ordered in D.06-06-063 should be filed in R.06-04-010. The monthly SRAC postings ordered in this decision shall be submitted to the Energy Division and posted on each IOUs' website.
This order is effective today.
Dated September 20, 2007, at San Francisco, California.
I will file a concurrence.
/s/ TIMOTHY ALAN SIMON
Commissioner
TABLES 1 - 7
ATTACHMENT A
SUMMARY OF STANDARD OFFER CONTRACTS FOR QUALIFYING FACILITIES
Summary of Standard Offer Contracts
for Qualifying Facilities (QFs)
Standard Offer Contract |
General Information |
Energy Payment |
Capacity Payment |
Standard Offer 1 (SO1) |
For as-available QFs, which cannot make a firm commitment to be available at peak times. |
Short-run avoided cost (SRAC) |
As-delivered capacity prices. |
Standard Offer 2 (SO2) |
Available for QFs who can make a firm commitment and maintain an 80% capacity factor during summer peak. Maximum contract term is 30 years. Temporarily suspended in Decision 86-05-024. |
SRAC |
Forecasted, fixed, and levelized capacity prices |
Standard Offer 3 (SO3) |
A simplified version of the SO1 available for QFs smaller than 100kW. Minimum contract term is one year. |
SRAC |
As-delivered capacity prices. |
Interim Standard Offer 4 (ISO4) |
Guarantees fixed payment rates for initial period of up to 10 years, to provide QFs with some certainty of return in their investments. Most contracts have by now reverted to SRAC. Contract term ranges from 15 to 30 years. Temporarily suspended in Decision 85-04-075. Permanently suspended in Decision 85-07-021, in anticipation of a final long-run contract. |
There are 3 energy payment options (EPO):
EPO2 - Fixed, forecasted, and levelized avoided energy costs for up to 10 years, after which they revert to SRAC. EPO3 - Based on fixed, forecasted utility Incremental Energy Rates (IERs) and current utility oil and gas costs, then reverting to SRAC. |
There are 3 capacity payment options (CPO):
CPO2 - Fixed, forecasted as-available capacity prices, which are not levelized, for up to 10 years, after which they revert to the higher of the as-delivered capacity price and the 10th year fixed capacity price. CPO3 - Fixed, forecasted, and levelized firm capacity prices for the term on the contract. |
Final Standard Offer 4 (FSO4) Never implemented |
QFs bid against the costs of the "identifiable deferrable resources" (IDRs), rather than against existing resources. On Feb.23, 1995 the FERC invalidated the FSO4 (also known as the Biennial Resource Plan Update - BRPU), ruling that the CPUC did not consider all potential sources of power in setting avoided cost prices. |
Period 1 - SRAC. Period 2 - Fixed, and ramped for inflation |
Period 1 - Fixed, ramped for inflation. Period 2 - Fixed, ramped for inflation. |
Non-Standard Contracts |
The utilities have also negotiated QF contracts whose terms do not conform to any of the standard offers. |
- |
- |
ATTACHMENT B
LIST OF ACRONYMS AND ABBREVIATIONS
LIST OF ACRONYMS AND ABBREVIATIONS | |
A. |
Application |
ACR |
Assigned Commissioner Ruling |
ALJ |
Administrative Law Judge |
AHR |
Administrative Heat Rate |
A/S |
Ancillary Services |
Btu |
British thermal unit |
CAC/EPUC |
Cogeneration Association of California and the Energy Producers and Users Coalition |
CAISO |
California Independent System Operator |
CARE |
Californians for Renewable Energy |
CCC |
California Cogeneration Council |
CCGT |
Combined Cycle Gas Turbine |
CDWR |
California Department of Water Resources |
CEC |
California Energy Commission |
CFR |
Code of Federal Regulations |
CHP |
Combined Heat and Power |
CMCP |
Competitive Market Clearing Price |
COB |
California-Oregon Border |
CPO |
Capacity Payment Options |
CPUC |
California Public Utilities Commission |
CT |
Combustion Turbine |
D. |
Decision |
DA |
Day-Ahead |
DEC |
Decremental |
DG |
distributed generation |
DH |
Davis Hydro |
DR |
demand response |
DRA |
Division of Ratepayer Advocates |
EAP II |
Energy Action Plan II |
ECAC |
Energy Cost Adjustment Clause |
EE |
Energy efficiency |
EEI |
Edison Electric Institute |
EPAct 2005 |
Energy Policy Act of 2005 |
EPO |
Energy payment options |
ERI |
Energy Reliability Index |
E3 |
Energy and Environmental Economics, Inc. |
FERC |
Federal Energy Regulatory Commission |
fn. |
footnote |
GMMs |
generator meter multipliers |
HA |
Hour-Ahead |
ICE |
Intercontinental Exchange |
Id. |
Idem, meaning "the same" |
IDRS |
identifiable deferrable resources |
i.e. |
id est, meaning "that is" |
IEP |
Independent Energy Producers |
IEPR |
Integrated Energy Policy Report |
IER |
incremental energy rate |
IMHR |
implied market heat rate |
INC |
incremental |
IOUs |
investor-owned utilities |
ISO |
Independent System Operator |
ITCS |
Interstate Transition Cost Surcharge |
KRCC |
Kern River Cogeneration Company |
kW |
Kilowatt |
kWh |
kilowatt hour |
LD |
Liquidated Damages |
LRAC |
run avoided costs |
LTPP |
Long-Term Procurement Plan |
MIF |
Market Index Formula |
mimeo. |
mimeograph |
MMBtu |
Million British thermal unit |
MOWD |
must-offer waiver denial |
MPR |
market price referent |
MRTU |
Market Redesign and Technology Upgrade |
MW |
megawatt |
MWD |
Megawatt Daily |
MWh |
megawatt hour |
NOPR |
Notice of Proposed Rulemaking |
NP15 |
North of Path 15 |
NYMEX |
New York Mercantile Exchange |
OIR |
Order Instituting Rulemaking |
O&M |
Operation and Maintenance |
ORA |
Office of Ratepayer Advocates |
p. |
page |
PG&E |
Pacific Gas and Electric Company |
PHC |
prehearing conference |
pp. |
pages |
PPAs |
power purchase agreements |
PRG |
Procurement Review Group |
Pub. Util. Code |
Public Utilities Code |
PURPA |
Public Utilities Regulatory Policy Act |
PV |
Palo Verde |
PX |
Power Exchange |
QFs |
Qualifying Facilities |
R. |
Rulemaking |
RA |
resource adequacy |
RCM |
RCM Biothane |
RECC |
real economic carrying charge |
Renewables Coalition |
California Landfill Gas Coalition and the California Wind Energy Association, jointly |
RFOs |
request for offers |
RMR |
reliability-must-run |
RPS |
Renewable Portfolio Standard |
RSO1 |
Revised Standard Offer 1 |
RT |
Reporter's Transcript |
SCE |
Southern California Edison Company |
SDG&E |
San Diego Gas & Electric Company |
SEPs |
Supplemental Energy Payments |
SGIP |
Self Generation Incentive Program |
SO |
Standard Offer |
SOC |
Standard of Conduct |
SoCalGas |
Southern California Gas Company |
SP15 |
South of Path 15 |
SRAC |
short-run avoided cost |
TOD |
Time of Delivery |
TOU |
Time-of-Use |
TURN |
The Utility Reform Network |
USCHPA |
U.S. Combined Heat and Power Association |
WACC |
Weighted Average Cost of Capacity |
WCC |
Watson Cogeneration Company |
(END OF ATTACHMENT B)
ATTACHMENT C
LIST OF APPEARANCES
************ APPEARANCES ************ |
Maureen Lennon |
Lisa M. Decker |
Crystal Needham |
William H. Booth |
Arthur L. Haubenstock |
Marion Peleo |
Berj K. Parseghian |
John Galloway |
Andrew Ulmer |
Susannah Churchill |
Donna J. Hines |
Jerry Oh |
********* INFORMATION ONLY ********** |
David Reynolds |
CALIFORNIA ENERGY MARKETS |
Janis C. Pepper |
Dan L. Carroll |
Ren Orens |
Brian T. Cragg |
Howard W. Choy |
Michael A. Yuffee |
William A. Monsen |
Ed Lucha |
Tom Jarman |
William P. Short |
Despina Papapostolou |
Tandy Mcmannes |
Janice Lin |
Lisa A. Cottle |
(END OF ATTACHMENT C)
115 Motion to Strike, Appendix C.
116 Cal. Code Regs., tit. 20, § 14.3, subd. (b) (emphasis added).
