9. 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 2013 Local Capacity Requirements study were discussed and recommended in an ISO stakeholder meeting, and they generally mirror those used in the 2007 through 2012 Local Capacity Requirements studies.

2. In previous RA decisions, the Commission delegated ministerial aspects of program administration to the Energy Division.

3. There is a need for refinements to the RA program to further define elements of flexibility with regard to multi-year contracts for local capacity requirements.

4. Proposals by Energy Division and the ISO to address flexible capacity, while helpful, require further consideration and detail before adoption.

5. The Energy Division presented a default proposal to update MCC buckets in the January 2012 workshops in this proceeding. This proposal updated load duration curves based on 2009, 2010 and 2011 data. Consistent with D.11-10-003, in its default proposal Energy Division also proposed a new MCC bucket for Demand Response resources.

6. D.05-10-042 adopted the current coincident adjustment methodology, which uses an average coincident adjustment factor to take advantage of the pooling effect.

7. An average coincidence factor across all customer classes hides certain cost differences among classes and LSEs.

8. An LSE-specific coincidence adjustment factor for hourly RA and an ESP composite coincidence factor for monthly RA more accurately allocates RA costs.

9. The Energy Division uses a rounding convention of 1 MW for RA compliance purposes, while the ISO uses a rounding convention of .01 MW for RA purposes.

10. The difference between the Energy Division and the ISO in RA rounding conventions can lead to small discrepancies, with sometimes leads to an LSE being deemed out of compliance by the ISO but not the Energy Division.

11. Small LSEs can have difficulty complying with an RA rounding convention which is too restrictive.

12. Currently, the ISO allows certain dynamically scheduled resources and pseudo tie resources to participate in ISO energy markets in order to give the ISO flexibility to operate these resources more efficiently in the ISO's markets and to dispatch them as needed. The methodology used to calculate the qualifying capacity of these resources is vague and needs specificity.

13. The June 21, 2011 CAC Petition seeks a modification to the system peak demand definition to exclude weekends and holidays from the hours used to calculate the qualifying capacity of combined heat and power resources. This proposal provides no significant benefits to the RA program through modifying the system peak demand resources.

14. In response to D.11-06-022, PG&E has proposed to change to the operational hours for its dynamic rates DR programs in compliance with the requirement for its Peak Day Pricing in its RDW application, which is pending Commission's approval.

15. D.11-10-003 allowed utilities to request an exemption to the 2013 requirement for specific demand response programs to be dispatchable by Local Capacity Area by 2013 in order to receive local resource adequacy credit under specified conditions.

16. The Commission did not issue D.12-04-045 approving PG&E's 2012-2014 demand response program budgets until April 19, 2012, subject to Advice Letter requirements between 60 to 90 days after the decision.

1. The ISO's 2013 Local Capacity Technical Analysis Final Report and Study Results, dated April 30, 2012, should be approved as the basis for establishing local procurement obligations for 2013 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. Energy Division should implement the local RA program for 2013 in accordance with the adopted policies in this and previous decisions.

4. Increased transparency and accurate cost information are Commission objectives in the resource adequacy program.

5. It is necessary to further consider issues related to flexible capacity in another portion of this proceeding.

6. It is reasonable to adopt the Energy Division's default MCC bucket proposal, including the creation of a new MCC bucket for Demand Response resources. The maximum percentage of Demand Response resources in this bucket should be determined in the RA template update.

7. It is reasonable to adopt a coincidence adjustment factor which includes an LSE-specific coincidence adjustment factor for hourly RA and an ESP composite coincidence factor for monthly RA.

8. Rounding to 0.1 MWs for Commission RA purposes is reasonable because this convention is much closer to the ISO's convention, will lead to a minimum of discrepancies between Energy Division and ISO reviews, and will not require different Commission standards for different LSEs.

9. It is reasonable to adopt the Energy Division proposal that, for purposes of qualifying capacity calculations used in the RA program, dynamically scheduled resources and pseudo tie resources should be treated as if they were internal ISO resources.

10. Load impacts related to PG&E's dynamic rate programs should be averaged over the interval of 2 p.m. to 6 p.m. for purposes of 2013 RA compliance as an exemption to RA rules, because PG&E's proposed changes to the operational hours for its dynamic rates DR program in its Rate Design Window application will not be approved in time for the next RA compliance filing.

11. PG&E's AMP, DBP, and CBP programs should count for RA in 2013 compliance year even though they are not yet locally dispatchable, as the timing of D.12-04-045 meets one of the requirements in D.11-10-003 for an exception from that decision's local dispatchability requirement for certain DR programs.

12. It is not reasonable to grant the June 21, 2011 Cogeneration Association of California Petition for Modification of D.10-06-036.

ORDER

IT IS ORDERED that:

1. The California Independent System Operator's 2013 Local Capacity Technical Analysis Final Report and Study Results, dated April 30, 2012, is adopted as the basis for establishing local procurement obligations for 2013 applicable to Commission-jurisdictional load-serving entities as defined by Public Utilities Code Section 380.

2. The "Option 2/Category C" Local Capacity Requirements set forth in the California Independent System Operator's 2013 Local Capacity Technical Analysis Final Report and Study Results, dated April 30, 2012, 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 2013 are as follows:

 

2013 Local Capacity Requirements Needs

    Local Area Name

Existing Capacity Needed

Deficiency

Total

(Megawatts)

    Humboldt

190

22

212

    North Coast / North Bay

629

0

629

    Sierra

1712

218

1930

    Stockton

413

154

567

    Greater Bay

4502

0

4502

    Greater Fresno

1786

8

1786

    Kern

483

42

525

    Los Angeles Basin

10295

0

10295

    Big Creek/

    Ventura

2241

0

2241

    San Diego

2938

144

3082

Total

25189

580

25769

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, D.10-06-036 and D.11-06-022 for compliance years 2008, 2009, 2010, 2011 and 2012, respectively, are continued in effect for compliance year 2013, subject to the modifications, refinements, and local capacity requirements adopted in the ordering paragraphs in this decision.

4. The resource adequacy program shall be modified so that the coincidence adjustment factor uses a load service entity-specific coincidence adjustment factor for annual resource adequacy requirements, and an energy service provider-composite coincidence factor for monthly resource adequacy requirements, as follows:

Annual Resource Adequacy Requirements - The California Energy Commission will calculate a Load Serving
Entity-specific coincidence adjustment factor using Load Serving Entity hourly loads; and

Monthly Resource Adequacy Requirements - The California Energy Commission will calculate an Electric Service Provider-composite coincidence factor, which would be applied to each Electric Service Provider's migrating load for the month; migrating load for community choice aggregators would be treated separately.

5. The resource adequacy program is modified so that load serving entities shall round to 0.1 MWs for resource adequacy compliance.

6. The resource adequacy program should be modified so that, for purposes of qualifying capacity calculations used in the resource adequacy program, dynamically scheduled resources and pseudo tie resources should be treated as if they were internal California Independent System Operator resources.

7. Energy Division shall update the percentages used for the current Maximum Cumulative Capacity uckets to reflect more current load shapes, to add a bucket specifically for Demand Response resources. These updates shall be implemented through the Energy Division's Resource Adequacy template. In implementing the new Maximum Cumulative Capacity Demand Response bucket, Energy Division shall set the upper limit of resources in the bucket after one or more workshops.

8. The June 21, 2011 Cogeneration Association of California Petition for Modification of Decision 10-06-036 is denied.

9. Load impacts related to Pacific Gas and Electric Company's dynamic rate programs shall be averaged over the interval of 2 p.m. to 6 p.m. for purposes of 2013 Resource Adequacy compliance.

10. Pacific Gas and Electric Company's Aggregator Managed Program, Capacity Bidding Program and Demand Bidding Program shall be counted for Resource Adequacy in the 2013 Resource Adequacy compliance year. These programs must be locally dispatchable by May 1, 2013.

11. Rulemaking 11-10-023 shall remain open.

This order is effective today.

Dated June 21, 2012, at San Francisco, California.

 

Previous PageTop Of PageGo To First Page