5. Assignment of Proceeding
Mark J. Ferron is the assigned Commissioner and David M. Gamson is the assigned ALJ in this proceeding.
1. The assumptions, processes, and criteria used for the 2012 LCR study were discussed and recommended in a CAISO stakeholder meeting, and they generally mirror those used in the 2007 through 2011 LCR studies.
2. In previous RA decisions, the Commission delegated ministerial aspects of program administration to the Energy Division.
3. A coincident factor is used in determining RA obligations by adjusting individual LSE peak forecasts for the fact that each LSE may or may not peak at the time of the CAISO coincident peak. D.05-10-042 adopted an average coincident adjustment factor methodology which uses historical coincident factors and the same coincident adjustment factor for all.
4. The rationale in D.05-12-042 for simplicity in adopting an average coincident factor for determining LSE RA requirements is no longer valid. The CEC currently uses two coincidence factors for purposes related to RA requirements; harmonizing these two factors would promote the goal of simplicity.
5. An average coincidence factor across all customer classes hides certain cost differences among classes and LSEs. In essence, this method serves as a cross subsidy from industrial and commercial customers to residential customers.
6. Because current Direct Access rules provide limited opportunities for customers to migrate between IOUs and ESPs, it is unlikely that a more accurate reflection of cost drivers stemming from the use of unbundled coincidence factors for different LSEs would significantly increase the incentive for some customers to migrate from IOUs to ESPs.
7. There is significant technical analysis which remains to be produced before the coincidence factor can be unbundled among LSEs for use in determining RA requirements.
8. The Standard Capacity Product is a system of availability metrics and performance penalties that RA resources face if they are subject to forced outages at rates above the overall fleet average.
9. D.09-06-028 deferred action on mandating the Standard Capacity Product for RA compliance for resources whose Qualifying Capacity was based on historical data, and for DR resources.
10. There remains considerable uncertainty as to how to apply the Standard Capacity Product for RA compliance for DR resources.
11. D.10-06-036 altered the RA net qualifying capacity rules to accommodate the Standard Capacity Product performance and availability provisions that are now accepted by FERC and in effect. The net qualifying capacity rules were modified in such as way as to remove a "double penalty" problem which was a barrier to implementation.
12. Violations of RA requirements in Commission decisions are subject to Commission-imposed penalties for procurement deficiencies, late filing, or other reasons.
13. D.10-06-036 adopted a revised penalty structure for violations of RA requirements. That decision contained penalties for deficiencies that are remedied within five business days.
14. The current penalty structure for violations of RA requirements can penalize LSEs for mistakes identified by agency staff soon after filings are submitted each month.
15. D.06-07-031 adopted a protocol for counting of units for RA purposes that take scheduled outages during the RA compliance year, for the purpose of determining resource availability.
16. The Commission's RA policy includes a "LSE-replace" rule whereby LSEs are only able to count generating units that are not impacted by scheduled outages towards meeting their RA obligations.
17. The current LSE-based replacement obligation for RA capacity for scheduled outages stands in the way of the making the Standard Capacity Product a commercially viable product.
18. SCE's proposed Planned Outage Adder essentially increases the Planning Reserve Margin by requiring all LSEs to contract for additional RA capacity regardless of the CAISO's need for it and whether RA units actually go on outage.
19. SCE's Planned Outage Adder proposal is less consistent with Commission goals of cost causation and cost minimization than the current scheduled outage requirement.
20. It is unclear what value the current scheduled outage rule provides in terms of reliability risk avoided by the rule. In addition, there is a significant administrative effort that goes into implementing the current rule.
21. There is no viable alternative to the LSE replace rule at this time.
22. In recent years, the median price paid for RA capacity, both system and Local, has been well below the RA waiver trigger price level.
23. The RA waiver trigger had been applied for only three times (and granted twice) since the 2007 compliance year. This fact shows that LSEs do not appear to be subject to market power in such a way as to make compliance with RA obligations impossible.
24. The Commission adopted the current Path 26 allocation in D.07-06-029, whereby the CAISO allocates a portion of the transfer capability on the path to LSEs based on proportionate share of their peak demand. The current process allocates the benefits on Path 26 to all LSEs.
25. D.05-01-042 adopted an informal process for LSEs to dispute and revise their year-ahead RA forecasts, but did not set clear timelines on the process.
26. It is becoming increasingly important for LSEs to have the opportunity to revise RA forecasts, due to greater level of uncertainty regarding future loads and customer retention.
27. The "best estimate" approach to forecasts of customer load migration adopted by D.04-10-035 requires LSEs to reasonably predict how much load they will serve in the upcoming compliance year, taking into account possible gain or loss of customers.
28. The Standard Capacity Product rules provide Scheduling Coordinators an opportunity to substitute non-RA resources for any RA unit to avoid being penalized for a deficiency. For Scheduling Coordinators in generation-constrained areas, there is no opportunity to make such a substitution since there are no available resources during off peak months because all available local resources are already committed through the Annual local RA obligation based on August forecasts.
29. The CAISO has identified problems in calculation and study modeling that would need to be satisfied to allow for determination of seasonal RA requirements. Identifying seasonal RA requirements would require a new time-consuming study.
30. D.10-06-036 continued aggregation of the "other PG&E" Local RA areas for the 2011 RA compliance year, due to market power concerns. This aggregation approach has been adopted yearly since 2006.
31. The preliminary local RA filing required by D.06-06-064 to facilitate coordination of the Local RA program with the CAISO's RMR process is an administrative cost to both LSEs and energy agencies that need to fulfill this requirement and process the filings. There is now only one RMR contract which would trigger this filing.
32. The 2006 Resource Adequacy guide allows the use of RA Portfolios for RA compliance purposes. RA Portfolios are plant-specific RA contracts, as opposed to unit-specific RA contracts. Since 2006, LSEs have only once used the process for submitting portfolio resources in their RA Filings.
33. Currently, there are a number of ways that DR resources differ from other supply resources in their ability to provide RA credit for LSEs.
34. All utility DR programs follow an RA Qualifying Capacity counting rule for resources with maximum event lengths of over two hours per call. The counting rules for all non-DR RA resources require that they must be available for a block of at least four consecutive hours on three consecutive days.
35. D.10-06-034 adopted a Settlement Agreement whereby the Settling Parties agreed to a Commission enforced annual limit designed to limit reliability-based DR program capacity to a specified percent of the CAISO's all-time coincident demand, which is currently 50,270 MW. In the settlement, there are annual RA credit caps plus a 10% tolerance band applicable to the emergency-triggered (also known as reliability-based) DR programs.
36. The total amount of IOU reliability-based DR programs eligible to count for 2012 is 1,658.9 MW. The reliability-based DR Programs subject to the caps are the IOUs' Base Interruptible Program, Summer Discount Plan, and Agricultural Pumping Interruptible Program.
37. Since the issuance of D.10-06-036, the CAISO developed the PDR program, which is a wholesale DR product.
38. D.10-06-036 changed the DR measurement hours effective in 2012 to 1:00 p.m. to 6:00 p.m. but allowed DR program operators to request exemptions. PG&E's PDP DR program operates from 2:00 p.m. to 6:00 p.m.
39. The next opportunity to change PG&E's current PDP is through its 2012 Rate Design Window application, which PG&E is required to file in February 2012.
1. The CAISO's 2012 Local Capacity Technical Analysis Final Report and Study Results, dated April 29, 2011, should be approved as the basis for establishing local procurement obligations for 2012 applicable to Commission-jurisdictional LSEs.
2. Because the current local RA program establishes procurement obligations for the following year, LSEs should only be responsible for procurement in a local area to the level of resources that exist in the area.
3. As in previous years, Energy Division should implement the local RA program for 2012 in accordance with the adopted policies in this and previous decisions.
4. Increased transparency and accurate cost information are Commission objectives in the RA program.
5. The average coincidence factor uses in determining RA requirements should not be unbundled among LSEs at this time, pending further study.
6. Due to recent actions of the FERC and the CAISO, it is now timely for the Commission to act to mandate the Standard Capacity Product for RA compliance for resources whose Qualifying Capacity was based on historical data.
7. It is reasonable to mandate the use of Standard Capacity Product penalties and availability metrics in RA contracts going forward, except for RA contracts involving DR programs.
8. It is reasonable to eliminate the current penalty for RA compliance deficiencies remedied within five days from the date of Energy Division notification in favor of a specific dollar penalty per instance without a daily multiplier.
9. In order to prevent LSEs from manipulating the RA compliance penalty structure and to deter intentional errors, after the second deficiency in any compliance year found by Energy Division and cured within five business days, LSEs should incur double penalties.
10. SCE's Planned Outage Adder method should not be adopted.
11. The current LSE-replace rule should be eliminated for the 2013 RA compliance year.
12. The RA trigger waiver price should not be changed at this time.
13. The Path 26 allocation process should not be changed at this time.
14. It is appropriate to provide added flexibility for LSEs to adjust their RA forecast.
15. There is no compelling reason that the "best estimate" standard of forecasting for RA compliance needs to change.
16. It is not reasonable to adopt seasonal RA requirements without a new CAISO study on this topic.
17. It is reasonable to permanently aggregate the "other PG&E" local areas for RA compliance purposes because the local area constraints in the "other PG&E" local areas have not changed since this aggregation was adopted, indicating market power mitigation is still needed.
18. The administrative costs associated with filing a Preliminary Local RA filing are unwarranted.
19. The option for using portfolio resources as a part of RA compliance should be eliminated.
20. To the extent possible, RA credit rules related to DR programs should be harmonized with RA credit rules related to conventional RA resources so DR resources can be integrated with the CAISO market.
21. It is reasonable to require that DR RA resources must be available for a block of at least four consecutive hours on three consecutive days in order to receive RA credit.
22. The Settlement Agreement adopted in D.10-06-034 should be implemented in this proceeding to adopt an enforced annual limit on reliability-based DR program capacity based on a specified percent of the CAISO's all-time coincident demand.
23. For the 2012 RA program, it is reasonable to allow PG&E an exemption from the requirement that its DR program operate from 2:00 p.m. to 6:00 p.m.
24. SCE did not make a timely request for an exemption from the requirement that its DR programs operate from 2:00 p.m. to 6:00 p.m. for 2012 RA purposes.
IT IS ORDERED that:
1. The California Independent System Operator's 2012 Local Capacity Technical Analysis Final Report and Study Results, dated April 29, 2011, is adopted as the basis for establishing local procurement obligations for 2012 applicable to Commission-jurisdictional load-serving entities as defined by Public Utilities Code Section 380, including but not limited to those entities listed in Appendix A to this decision.
2. The "Option 2/Category C" Local Capacity Requirements set forth in the California Independent System Operator's 2012 Local Capacity Technical Analysis Final Report and Study Results, dated April 29, 2011, are adopted as the basis for establishing local resource adequacy procurement obligations for load-serving entities subject to this Commission's Resource Adequacy Program requirements. The Local Capacity Requirements for 2012 are as follows:
2012 Local Capacity Requirements Needs | |||
Local Area Name |
Existing Capacity Needed |
Deficiency |
Total (Megawatts) |
Humboldt |
190 |
22 |
212 |
North Coast / North Bay |
613 |
0 |
613 |
Sierra |
1685 |
289 |
1974 |
Stockton |
389 |
178 |
567 |
Greater Bay |
4278 |
0 |
4278 |
Greater Fresno |
1899 |
8 |
1907 |
Kern |
297 |
28 |
325 |
Los Angeles Basin |
10865 |
0 |
10865 |
Big Creek/ Ventura |
3093 |
0 |
3093 |
San Diego |
2849 |
95 |
2944 |
Total |
26158 |
620 |
26778 |
3. The local Resource Adequacy Program and associated requirements adopted in Decision (D.) 06-06-064 for compliance year 2007, and continued in effect by D.07-06-029, D.08-06-031, D.09-06-028, and D.10-06-036 for compliance years 2008, 2009, 2010 and 2011, respectively, are continued in effect for compliance year 2012, subject to the modifications, refinements, and local capacity requirements adopted in the ordering paragraphs in this decision.
4. The Standard Capacity Product adopted in Decision 09-06-028 shall be a mandatory part of the Resource Adequacy compliance program for all Load Serving Entities (as defined by Public Utilities Code Section 380).
5. The penalties for Resource Adequacy program violations set forth in Decision 10-06-036, Ordering Paragraph 6(g) are modified to eliminate penalties for deficiencies remedied within five business days after notification from Energy Division with the application of a specified violation for deficiencies added to Resolution E-4195. For deficiencies not remedied within five business days, penalties shall be as follows:
System Procurement Deficiency |
Local Procurement | |
Deficiency remedied after five business days from the date of Energy Division notification or not remedied at all |
$6.66/kilowatt-month |
$3.33/kilowatt-month |
6. As shown in Appendix B to this decision, Appendix A to Resolution E-4195 is modified to incorporate the creation of a new Specified Violation for Load Serving Entities (as defined by Public Utilities Code Section 380) that remedy deficiencies within five business days after notification by Energy Division staff. This new Specified Violation replaces in total the current Specified Violation for Small Procurement Deficiencies. Other Specified Violations from Appendix A to Resolution E-4195 will remain and continue to be used. The new Specified Violation shall be as follows:
Specified Violation |
Deficiency in either System or Local Resource Adequacy Filing |
Deficiency cured within five business days from the date of notification by Energy Division |
$5,000 per incident if the deficiency is 10 Megawatts (MW) or smaller, or $10,000 for a deficiency larger than 10 MW. For the second and each subsequent deficiency in any calendar year, penalties will be $10,000 per incident if the deficiency is 10 MW or smaller, or $20,000 for a deficiency larger than 10 MW. |
7. For the 2012 Resource Adequacy compliance year only, Load Serving Entities (as defined in Public Utilities Code Section 380) shall continue to use the scheduled outage rules adopted in Decision 06-07-031. Beginning in the 2013 Resource Adequacy compliance year, the "LSE-replace" rule of the scheduled outage rules is eliminated.
8. The schedule for all Load Serving Entities (LSEs) (as defined in Public Utilities Code Section 380) to file year-ahead Resource Adequacy (RA) forecasts and revisions shall be as follows for 2012, subject to the modification by the Assigned Commissioner or assigned Administrative Law Judge:
Filing |
Due |
Days before Year-Ahead |
LSEs file Historical load info |
15-Mar |
230 |
LSEs file 2012 Year-Ahead Load Forecast |
22-Apr |
192 |
LSEs receive 2012 Year-Ahead RA obligations |
25-Ju |
98 |
Final date to file revised forecasts for 2012 |
19-Aug |
73 |
LSEs receive revised 2012 RA obligations |
15-Sep |
46 |
LSEs receive RMR allocations |
7-Oct |
24 |
LSEs file Final 2012 Year-Ahead RA Filing |
31-Oct |
0 |
9. The determination in Decision 10-06-036 that the Humboldt, North Coast/North Bay, Sierra, Stockton, Greater Fresno, and Kern local areas within the Pacific Gas and Electric Company (PG&E) territory (known as "other PG&E" local areas) were aggregated for Resource Adequacy compliance purposes for 2011, is made permanent for 2012 onward.
10. Load Serving Entities (LSEs) (as defined in Public Utilities Code Section 380) are not required to file a Preliminary Local Resource Adequacy Filing. However, LSEs that contract with any resources with an existing Reliability Must Run Contract must inform the California Independent System Operator and the Commission's Energy Division via email by the second Monday in September of each year.
11. Load Serving Entities (as defined in Public Utilities Code Section 380) are no longer permitted to use Portfolio Resources as Resource Adequacy capacity, as previously authorized in Decision 06-07-031.
12. The following language from Ordering Paragraph 16 in Decision 05-10-042 shall apply to all demand response resources in the Resource Adequacy program: "to qualify for [resource adequacy requirements], a resource must (1) be able to operate for a minimum of four hours per day for three consecutive days ..."
13. For the 2012, Resource Adequacy compliance year, demand response program totals allocated towards Resource Adequacy credit for the Base Interruptible Program, the Summer Discount Plan, and the Agricultural Pumping Interruptible Program shall be less than or equal to 543.9 Megawatts for Pacific Gas and Electric Company; 1087.8 Megawatts for Southern California Edison Company; and 27.2 Megawatts for San Diego Gas & Electric Company, if the three utilities' total load impact from these programs exceeds the aggregated cap of 1,658.9 Megawatts.
14. For the 2012 Resource Adequacy compliance year only, Pacific Gas and Electric Company's (PG&E's) Peak Day Pricing (PDP) program is granted an exemption from the requirement in Decision 10-06-036 that demand response programs must operate from 1:00 p.m. to 6:00 p.m. in order to receive full Resource Adequacy credit, so that in 2012, PG&E's PDP which operates from 2:00 p.m. to 6:00 p.m. shall receive full Resource Adequacy credit for these hours.
15. Rulemaking 09-10-032 shall remain open.
This order is effective today.
Dated June 23, 2011, at San Francisco, California.
MICHAEL R. PEEVEY
President
TIMOTHY ALAN SIMON
CATHERINE J.K. SANDOVAL
MARK J. FERRON
Commissioners
I abstain.
/s/ MICHEL PETER FLORIO
Commissioner
