PHASE TWO / TRACK ONE
California Public Utilities Commission
March 30, 2007
TABLE OF CONTENTS
1. Procedural Background....................................................................3
2. Zonal Capacity Requirement in Resource Adequacy (RA).........................4
a. Need for Zonal RA..................................................................4
b. Implementation Proposals to Satisfy a Need....................................5
3. Local RA.......................................................................................6
a. Probabilistic Local Capacity Requirement (LCR) Study......................6
b. Split Peak and Off Peak (Seasonal) LCR Study................................7
c. Load Migration Issue in RA and Proposal.......................................8
d. Aggregation of Local Areas.......................................................9
e. Waiver of Resource Deficiencies in Local Areas.............................10
4. Demand Response (DR) in RA Program..............................................10
a. DR for Local RA..................................................................10
b. Emergency and Interruptible DR programs in RA...........................11
5. Load Forecast and RA Compliance Year.............................................12
a. Load forecast in RA...............................................................12
b. RA Compliance Year.............................................................13
6. RA and Backstop Mechanism...........................................................14
7. Assembly Bill 1969.........................................................................16
8. CPUC Staff Proposals for Implementation in Current RA Program...........16
a. RA Rounding Convention for System and Local.............................16
b. Qualifying Capacity (QC) for Newer Wind Units............................17
9. Other Issues Discussed in the Workshop...............................................18
10. Next Steps in RA Rulemaking 05-12-013..............................................18
Appendix A-Acronyms Used in Workshop Report.........................................19
1. Procedural Background
This Workshop Report is submitted consistent with Commissioner Peevey's Assigned Commissioner's Ruling (ACR) and Scoping Memo issued by the California Public Utilities Commission (Commission) on December 22, 2006 for Phase Two of Resource Adequacy (RA) Rulemaking (R.) 05-12-013. Interested parties in the RA proceeding filed their proposals on Track One issues in Phase Two on January 26, 2007. The California Public Utilities Commission staff (CPUC staff) facilitated three workshops on February 8, February 20 and 21, and March 8, 2007 at the Commission's Headquarters in San Francisco discussing Track One issues. Interested parties have the opportunity to explore Track One issues before filing comments on April 6, 2007 and before the Commission issues its final decision on Track One issues in RA on June 21, 2007.
The workshops focused on Track One issues in Phase Two of RA as identified by the ACR. Track One issues are near-term RA program issues for 2008 and 2009. The issues identified by the ACR for Track One were:
· Local RA based on the California Independent System Operator (CAISO) 2008 Local Capacity Requirement (LCR) study and report
· Review of LCR study methodology
· Changes to Local RA program implementation including monthly compliance filings
· Probabilistic LCR assessment linked to the grid planning process
· Zonal RA requirements
· Demand Response (DR) program impacts and dispatch
· Coordination of the RA program with the California Energy Commission (CEC) load forecasting processes, including whether to allow for or require changes to Resource Adequacy Requirement (RAR) if the CEC load forecast changes
· Coordination of RA program and a backstop mechanism
· Implementation of Assembly Bill (AB) 1969 for RA purposes
· Minor implementation topics
The purpose of this report is to identify points of consensus reached by the workshop participants, identify issues where agreement does not exist, and set forth options for resolving issues to the extent that is feasible. This report is not intended to define the policy preferences for either the Commission or CEC. The staff from each agency worked collaboratively in drafting this report and worked together in facilitation of the workshop for Track One issues in Phase Two of the RA proceeding. It is also important to note that the CAISO released its 2008 LCR study on March 9, 2007 and that the 2008 LCR study was not discussed in the workshops hosted by CPUC staff. The CAISO hosted a public stakeholder meeting on March 21, 2007 to discuss the 2008 LCR study. The content of that workshop is not covered in this report.
2. Zonal Capacity Requirement in RA
A. Need for Zonal RA
On February 8, 2007, the CAISO led a presentation and discussion regarding a zonal capacity need for RA workshop participants. The CAISO presentation focused on establishing the factual basis of a possible need for a zonal RAR. During the presentation, the CAISO presented its assumptions, zonal capacity calculation methodology, zonal capacity illustrations, and a zonal capacity reliability need summary. The zonal need expressed by the CAISO centered around both north (NP26) and south (SP26) constraints on Path 26. The CAISO identified NP 26 as its electrical footprint north of Path 26 and generally known as NP 15 and ZP 26. The CAISO also identified SP 26 as its electrical footprint south of Path 26. The CAISO indicated a residual zonal capacity need in the amount of 6,290 MW for NP 26 and 7,566 MW for SP 26. The total zonal capacity need identified was 13,856 MW. Various parties expressed concern for the establishment of an additional capacity requirement and inconsistencies with underlying assumptions that were used by the CAISO for existing Local and System RA requirements.
During this workshop, Southern California Edison Company (SCE) raised a proposal to address zonal issues presented by the CAISO by placing a constraint on the amount of capacity Load Serving Entities (LSEs) may count crossing Path 26. The CAISO made a preliminary identification that a 4,000 MW transfer capability exists on Path 26. Based on this fact, parties proposed that LSEs with load south of Path 26 would be limited to 4,000 MW coming from north of Path 26. Similarly, LSEs with load north of Path 26 would be limited to 4,000 MW coming from south of Path 26. A formula for this type of allocation was not agreed upon and the CAISO committed to exploring whether this option could meet the reliability needs established in RA. CPUC Staff instructed all parties at the workshop to be prepared to discuss this matter further in the next RA workshop scheduled for February 20 and 21, 2007. Parties were also directed to be prepared to discuss alternative methods for implementing a Zonal requirement in the RA program.
The concept of a need for some form of Zonal RA was further discussed by workshop participants on February 21, 2007 after a CAISO presentation on Path 26 constraints. The workshop participants appeared to reach consensus that there is a legitimate need to address constraints on Path 26. However, parties did not reach consensus on the size or amount of the zonal capacity need or the methodology for calculating such a need.
The CAISO committed to make refinements to its zonal need proposal to the parties. Specifically, the CAISO was to conduct further analysis on loop flows and Existing Transmission Contracts (ETCs) on Path 26. The CAISO committed to providing the results of its refined Zonal RA proposal to the RA proceeding service list by March 22, 2007.
B. Implementation Proposals to Satisfy Need
Parties discussed implementation proposals to satisfy a possible zonal capacity need identified by the CAISO on February 21, 2007. SCE formally presented a proposal for implementation that would cure the need for a zonal RAR caused by limitation constraints on Path 26. The proposal established a general concept for RA counting on Path 26 for System RA in lieu of an explicit Zonal RA procurement requirement. The proposal consisted of five steps. These steps were:
· Step 1: CAISO determines transfer capability of Path 26 by separating north to south and south to north transfer capabilities for RA counting purposes.
· Step 2: In a preliminary filing, LSEs submit RA resources under contract that need to use Path 26 to reach the LSEs load.
· Step 3: CAISO determines the incremental impact on Path 26 capacity based on the preliminary filing made by LSEs to help determine the impact of netting. This step gives path priority to resources under contract, but also increases the capacity for flows counter to the contract.
· Step 4: The net impact identified in Step 3 is then combined with the total transfer capability from Step 1 to determine the remaining Path 26 RA capacity to be allocated to LSEs based on their share of load in the zone.
· Step 5: LSEs include as part of their year-ahead and month-ahead RA compliance filing Path 26 RA counting rights in order to count RA resources that need to use Path 26 to reach the LSEs load towards their RA requirements.
SCE claimed that its Path 26 RA counting approach would ensure appropriate regional balance of RA resources, explicitly recognizes Path 26 for RA counting purposes, allows the CAISO to determine the total amount of Path 26 RA counting rights, allocates RA counting rights to LSEs for Path 26, provides an iterative allocation process that recognizes the netting of north-to-south and south-to-north transfers, and provides LSEs sufficient Path 26 RA capacity to count resources located outside their zone as System RA, including RA imports. Additionally, SCE claimed that its implementation proposal would permit the CAISO to conduct necessary backstop procurement to cure system deficiencies caused by zonal constraints, does not require significant modification of existing RA counting rules, and specifically does not require a Zonal RAR. SCE's implementation proposal needed more discussion on issues including:
· Quantity of RA counting rights available on Path 26 including: existing RA resource commitments, ETCs, and loop flow
· Treatment of existing RA resource commitments that utilize Path 26 including: honoring commitments made based on existing RA rules versus a pure pro-rata allocation
· Timing of allocation and showings for Path 26 RA counting rights
· Integration with the CAISO backstop procurement
The Commission's Division of Ratepayer Advocates (DRA) also made an alternative proposal to address the possible zonal need identified by the CAISO on February 21, 2007. The DRA proposed that the Commission establish in the RA program minimum percentages of System RA that must be provided by RA capacity that is located in either SP 26 or NP 26. The minimum percentages would depend on each zone's load, demand response capacity, imports, Path 26 transfer capability, and Department of Water Resources (DWR) and Liquidated Damages (LD) contracts. Procurement requirements around NP 26 and SP 26 to satisfy zonal capacity deficiencies would be identified each year by the CAISO. The percentage zonal requirement may thus change year to year based on changing needs. Workshop participants provided feedback on this alternative implementation proposal indicating that this method would create a large zonal capacity market. Workshop participants expressed the need for this proposal to be refined for further consideration.
SCE and DRA were requested by CPUC staff to provide revised proposals to the RA proceeding service list by March 22, 2007 for review and further consideration. Specifically, parties at the workshop requested the refined implementation proposals for addressing a possible zonal need to include the following:
· Load forecast, planning reserve margin (PRM), contingency, and other factors upon which RAR is based,
· Allocation methods used identifying impact on existing RA commitments and Existing Transmission Contracts (ETCs),
· Load migration between zones,
· Counter-flows over Path 26 and netting,
· Market power and incentives for new generation/transmission,
· RA template and guide changes and any new information requirements needed,
· Backstop procurement (who does, when, what process, and who pays), and
· Grid reliability.
3. Local Resource Adequacy
A. Probabilistic Local Capacity Requirement (LCR) Study
The Commission indicated in D.06-06-064 the need for the CAISO to take a lead role in moving to a probabilistic approach for future LCR studies. The ACR and Scoping Memo issued by the Commission on December 22, 2006 also directed the CAISO to include with its 2008 LCR study report: (a) a discussion of how probabilistic analysis can be incorporated into future LCR studies, (b) its recommendations on the steps to be taken on this topic, and (c) its recommendation as to the actions that the Commission should take on this topic.1
The CAISO made its presentation for pursuing a probabilistic derived LCR study to workshop participants on March 8, 2007. The CAISO provided an overview of the data needs and a timeline for a probabilistic study was provided. In the presentation, the CAISO estimated that from the granting of initial funding for this study and gaining commitment from CAISO management, that a proposed probabilistic study can be completed for consideration for implementation in the RA program within two years.
The probabilistic study would determine the Loss of Load Probability (LOLP) for each Local Area in RA, which could be used in setting future Local RAR. Some milestones identified by the CAISO were: adopting a LOLP methodology, evaluation and purchase of software, data needs identification and gathering, study assumptions and stakeholder input, data loading and modeling, first run results, a stakeholder review, and production of final results. Additionally, the CAISO recommended using the Locational Study Advisory Group (LSAG) to address the technical issues involved with a LOLP study. The LSAG was established in 2007 to explore and validate the assumptions underlying the 2007 and 2008 LCR study.
CAISO commitments to LOLP were to develop an understanding of the broader application and fit of LOLP within the CAISO planning function and to seek technical expertise to provide guidance and planning.2
Parties at the workshop commented that the need and benefit for a probabilistic study requires further discussion. Specifically, parties commented that the issues of when this study should be completed, identifying what problems the study can help to resolve, benefits to expect, and whether the benefits outweigh the cost for spending resources to complete a LOLP study need more consideration.
Additionally, the CAISO released its 2008 LCR Study following the RA workshops on March 9, 2007. The CAISO also posted a public market notice for the 2008 LCR study on March 9, 2007. Public stakeholders may review the report and were invited to participate in a LCR stakeholder meeting on March 21, 2007 hosted by the CAISO.
B. Split Peak and Off Peak (Seasonal) LCR Study
Parties have suggested seasonal variations in the LCR. Within the current RA program, parties have indicated that 1-in-10 summer peak loads do not occur year round.
The CAISO presented the technical hurdles, operational impacts, and programmatic issues involved with incorporating a seasonal LCR study in the RA program3. Technical hurdles involve LCR study assumptions and impacts such as planned outages, resource portfolio effectiveness, transmission capability into Local Areas, and deliverability of resources off of peak.
Operational impacts for consideration include impacts on the CAISO's outage coordination process. The CAISO claimed that under a seasonal LCR program the current first come and first served outage coordination process may no longer be sustainable. This may then lead to the CAISO taking extra steps to consider RA agreements when approving planned outages and it may also lead to the need to align the timing of the LCR study process with the availability of best and most current outage information. Furthermore, the CAISO conveyed in its presentation that there may be a greater potential to rely on backstop procurement because resource assumptions on effectiveness in meeting contingencies may not be valid with a potentially lower LCR. This could lead to the RA resource mix not being adequate in lower load situations.
In addition, the CAISO identified programmatic issues impacted by implementing a seasonal LCR into the RA program. These key issues were:
· A seasonal LCR would require a reevaluation of resource deliverability and import capability
· Much of the LCR effort and processes for LSEs would be doubled such as seasonal versus annual LCR showings
Workshop participants expressed a need for more analysis on the cost versus the benefit of a seasonal LCR in the RA program. This includes an understanding of a seasonal LCR study data needs and projected timeline for such a study. The CAISO pointed out that it is unclear how a seasonal LCR reduces overall costs and that a seasonal LCR potentially reduces RA capacity available to the CAISO. Overall, parties indicated the need to better understand the benefits and impacts of a seasonal LCR in RA and that this issue needs more development and discussion.
C. Load Migration Issue in RA
Currently, LSEs must procure to meet 100 percent of their Local RAR on a year-ahead basis. D.05-10-042 outlined a process to adjust an LSE's System RAR for load migration on a monthly basis. LSEs were directed to submit revised load forecasts two months prior to the filing month, which is one month prior to the RA monthly filing due date. Load forecast adjustments were allowed solely for the purposes of accounting for load migration.
On February 20, 2007, Sempra Energy introduced a proposal for modifications to the Local RA rules. The proposal consisted of a 90 percent year-ahead Local RAR by LSE's and a month-ahead Local RAR process that would allow for monthly true-ups.4 The proposal was as follows:
· Year-Ahead Local RA Procurement:
o CAISO determines Local RAR for each Load Pocket.
o CEC assigns Local RAR to each LSE.
o LSE procures 90% of its Local RAR for the year-ahead RA compliance filing.
_ Residual is procured with month-ahead true-ups.
_ Residual procurement maintains liquidity in the market and a premium price on Local RA capacity.
The benefits of this proposal would include: month-ahead load forecast adjustments made by LSEs, true-up of residual System and Local requirements simultaneously, allowance for load migration adjustments by LSEs, maintenance of liquidity of Local RA capacity and System RA capacity through active monthly procurement activities of LSEs, the establishment of a premium on Local RA capacity, and better accounting of load migration.
Parties in the workshop requested more numerical examples to be provided. Parties also expressed concern of how liquid of a market could exist for Local RA capacity and that there is no mechanism in place such as a bulletin board to allow for such monthly true-ups. In addition, the question of whether to use a MW allocation as opposed to a percentage of system or local was raised. Upon evaluation of this concern, Sempra and workshop participants appeared to reach consensus that a MW allocation would be better than a percentage allocation.
Sempra committed to continue to refine the proposal for monthly Local RA adjustments and to provide clear numerical examples with a revised proposal that would be submitted to the RA proceeding service list by March 22, 2007 for review. The revised proposal would demonstrate how the RA program would be improved and implemented via the existing RAR templates.
D. Aggregation of Local Areas in RA
Decision 06-06-064 established aggregation of Local Areas for the 2007 Local RAR. The aggregation of Local Areas has two components. The first component is determining each LSE's allocation of Local RAR for each Local Area. The second component is determining which Local Areas are aggregated for a combined showing.
The Commission determined that each LSE's allocation of 2007 Local RAR for each Local Area would be based on its share of load in the Investor Owned Utility (IOU) distribution service area. It also determined that six Local Areas within the PG&E territory (Humboldt, North Coast/North Bay, Sierra, Stockton, Greater Fresno, and Kern) should be aggregated as one for purposes of Local RAR for compliance year 2007.5
During the February 21 workshop, stakeholders reached consensus in favor of a CPUC staff proposal that (1) continues to calculate Local RAR based on load share of IOU distribution service area, and (2) continues the aggregation of PG&E Local Areas, as implemented in 2007, for RA compliance year 2008.6 However, workshop participants expressed the concern that there will be a need to reevaluate the aggregation of Local Areas in future years. The workshop did not address allocation issues related to the Ventura-Big Creek Local Area proposed in the CAISO's 2008 LCR study.
E. Waiver of Resource Deficiencies in Local Areas
Several parties in the past requested that the Commission allow waivers from Local procurement obligations under certain conditions. A waiver process was determined to be necessary for market power mitigation and was adopted as a component of the Local RAR program. A waiver process and a trigger price was developed to evaluate waiver requests from LSEs in D.06-06-064. Under the current waiver process, a LSE is able to request relief from its procurement obligation with a demonstration that it has made every commercially reasonable effort to contract for Local RAR resources. A deficient LSE is still responsible for any applicable backstop procurement costs even if it received a waiver from penalties. The Commission also expressed interest in exploring additional objective criteria for waiver requests and other refinements to the waiver process that can be developed and implemented during its next phase of the RA proceeding.
CPUC staff proposed continuing the process for waiver of resource deficient LSEs for RA compliance year 2008 in the workshop on February 21, 2007.7 Consensus was reached with workshop participants in favor of continuing this process for compliance year 2008. However, workshop participants also expressed concern that the issue of LSE procurement deficiencies and a waiver process will need to be evaluated in future years.
4. Demand Response (DR) in the RA Program
A. Demand Response for Local RA
The RA program currently allows dispatchable DR resources to be "taken off the top" of an LSE's System RAR procurement obligation. The CEC allocates DR program impacts to LSEs for their use in RA compliance. Commission D.06-06-064 determined that dispatchable DR credit should also be allocated to each Local Area and counted for Local RAR to the extent that is feasible, but that it may not be possible for the 2007 compliance year. San Diego Gas and Electric Company (SDG&E) also proposed a methodology and requested DR resources be allocated to LSEs within its distribution service area. CPUC Staff performed the allocation for use in the 2007 San Diego Local Area RA. In an effort to move the RA program forward for compliance year 2008, SCE and Pacific Gas and Electric Company (PG&E) gave presentations on DR for Local RA in the March 8, 2007 workshop.
SCE presented a methodology for allocation of DR resources for Local RA. In the presentation, SCE commented that the allocation of DR resources by Local Areas has different challenges based on the methodology used. The methodologies presented by SCE were estimation of customer impact by zip code and by substation. Estimation by zip code presents accuracy limitations and estimation by substation would require a data intensive effort. Additionally, SCE claimed that when customer impacts are estimated by zip code, approximately 70 percent of SCE's total DR resources would apply to the Local Area.8 SCE estimated that it would take about 90 days to fully develop a plan for DR allocation for Local Areas. Further cooperation between SCE, CEC, the Commission, and the CAISO may lead to continued development on the feasibility of DR for Local RA. SCE has expressed confidence that this can be completed in time for data to be evaluated as part of the 2008 RA compliance year DR allocation process.
PG&E stated in its presentation that it should be able to determine the amount of DR that is located within each load pocket. PG&E supports modifying all DR programs to allow load to be dispatched by proposed load pockets, instead of defined demand zones.9 PG&E presented characteristics of its existing DR programs including price responsive and reliability programs. PG&E also included subscribed load reduction by program in its presentation. PG&E agreed to provide additional data during the presentation for follow-up consideration. This data is to include program triggers, RA adjusted MW, and the duration of call by program.
The development of feasible DR allocation for Local RA needs to be continued in order to take effect. During the workshop, parties agreed that further cooperation between PG&E, CEC, the Commission, and the CAISO would lead to the continued development on this issue. PG&E also expressed confidence that this could be completed in time for data to be evaluated as part of the 2008 compliance year DR allocation process.
B. Emergency and Interruptible DR Programs in RA
DR programs reduce load and therefore reduce the need for generation resources. There are two basic types of DR programs: reliability programs that are activated during periods of system stress and price responsive programs where energy users are paid to reduce consumption when energy prices are high. Both DR programs are used in RA and allocations from the CEC are derived from counting conventions based on historical performance. The CEC analysis for DR allocations includes: restrictions established in Commission D.05-10-042, DR programs that must be dispatchable, have a 48-hour minimum availability requirement, and programs operate only two-hours per day are limited to 0.89 percent of monthly peaks.
In the workshop on February 20, 2007, CPUC staff facilitated a discussion on interruptible DR programs and RA allocations for DR. The CAISO asserted that DR programs that can not be called before system emergencies should not count for RA. . Some parties replied that LSE's/ratepayers should not have to pay for programs that do not count and that not counting the programs implies that they do not have value. The CAISO expressed support for continuing the DR emergency programs as they have operational value, but reiterated that they do not believe the emergency DR programs should count for RA. Various parties stated that current DR programs and how they fit in RA may need refinement and that DR operating protocols may need to be better aligned with the needs of the CAISO.
CPUC staff reiterated to the workshop participants that DR protocols governing operations are outside the scope of the RA proceeding and that Rulemaking (R.) 07-01-041 was established by the Commission on January 25, 2007 to address the following:
_ The establishment of a comprehensive set of protocols for estimating the load impacts of DR programs,
_ The establishment of methodologies to determine the cost-effectiveness of DR programs,
_ The setting of goals for 2008 and beyond and the development of rules on goal attainment, and
_ The consideration of modifications to DR programs needed to support the CAISO'S efforts to incorporate DR into market design protocols.
CPUC staff also stated that RA allocations for DR would continue to be based on historical performance and that the Commission would be mindful of decisions in the new DR rulemaking to ensure that the RA program adapts as DR programs, operating rules, and protocols continue to evolve.
5. Load Forecast and RA Compliance Year
A. Load Forecast in RA
The RA program relies on the load forecasts supplied to and checked by the CEC as the foundation for each LSE's RAR. In order to establish the System RAR, CEC reviews the load forecast submitted by each LSE, reconciles the aggregate of those load forecast against its own forecast for each IOU service territory, and generates an individual load forecast for each LSE for each month of the year. LSEs currently submit a year-ahead load forecast for its System RAR and then submit monthly load forecasts two months in advance of the applicable month to allow for load migration.
CPUC staff observed some concerns with the accuracy of load forecasting and load migration in its RA compliance reviews. The timing of the two-month-ahead load forecast can make it difficult to account for the new customers or actual retention rates of existing customers when significant changes occur. CPUC staff presented load forecasting and the load migration issues to the workshop participants on February 8, 2007. CPUC staff observed that LSEs frequently had load migration that was stable from month to month and that ESPs generally forecasted their load by accounting for known and expected load retention, but not new accounts. CPUC and CEC staff proposed a new quarterly load forecast to replace the monthly load forecasts, however, parties expressed concern regarding the upward and downward limitations that were proposed for implementation in the new quarterly load forecast process.
A revised quarterly load forecast process was proposed by CPUC and CEC staff at the workshop on March 8, 2007. The objective of the proposal was to increase the accuracy of load forecasting, support the development of quantitative forecast accuracy standards, reduce the amount of load that is unaccounted for in the current RA program, provide flexibility for LSEs in making monthly load forecasting adjustments, and to eliminate unnecessary filings. The revised quarterly load forecasting proposal specifically addressed downward adjustments. Under the revised proposal, the CEC would need to pre-approve month-ahead downward load forecast adjustments of more than the lesser of 100 MW or 20 percent from the original quarterly load forecast by an LSE. The revised proposal also did not place restrictions on upward adjustments of load forecasting adjustments.
Overall, the workshop participants expressed concerns about the after-the-fact review of load forecasts to actual loads, Commission enforcement of accuracy provisions, and penalty mechanisms for excessive error that were not clearly defined. Consensus was not reached at the workshop and parties were invited to submit comments on this proposal on April 6, 2007.
B. RA Compliance Year
CPUC staff introduced to workshop participants the concept of better coordinating future RA program compliance year with the annual load forecasting process by the CEC on February 20, 2007. CPUC staff introduced the idea of having a RA program year of May through April instead of January through December. Parties have commented that coordination of RA program with the CEC's load forecasting process for 2008 and beyond could be improved by changing the timing of the System RA program year to start at the beginning of summer, instead of January 1st. For example, the PJM ISO operates on a May to April compliance year. Parties have commented that the benefit of changing the RA program year to start at the beginning of summer would be to enable LSEs to adjust their procurement to meet their RA requirements. This would in turn reflect the CEC's updated, post-summer load forecast that becomes available in the fall of every year.
Generally, workshop participants were open-minded about considering changing the RA program year for the benefit of incorporating more accurate load forecasting data from the CEC for RAR obligations to the extent that this is feasible. However, the feasibility of better coordination as proposed needed more refinement. Specifically, parties expressed the need to review a proposal for a draft compliance year for 2009 to evaluate the feasibility on a changed program year in RA. CPUC staff indicated that it would develop a draft proposal for compliance year 2009 that would be more aligned with the CEC's load forecasting process and that this would be provided to public stakeholders for review and further discussion.
6. RA and Backstop Mechanism
One of the Commission's long-term objectives is to minimize the use of the Reliability Must-Run (RMR) process and D.06-06-064 acknowledged that the RMR process would remain in place as a backstop reliability mechanism for 2007.10 An alternate backstop mechanism that the CAISO uses is the Reliability Capacity Services Tariff (RCST). However, RCST is scheduled to expire at the end of 2007. The Federal Energy Regulatory Commission (FERC) may approve an extension of RCST for the CAISO due to delayed implementation of its Market Redesign and Technology Upgrade (MRTU) that is currently planned in 2008.
Due to the uncertainty of when an RCST extension or replacement will be approved by FERC, coordination of the RA program for 2008 and possibly beyond with any backstop mechanism was addressed by the CAISO for discussion in the workshop on February 20, 2007. Specifically, the CAISO discussed a proposal for continuing a minimal usage of RMR in 2008 and using RCST as an interim backstop mechanism in 2008 until MRTU can be implemented. The CAISO also committed to convene a public stakeholder process in April 2007 for development of a new backstop mechanism that would meet the needs of the CAISO's MRTU.
In the March 8th workshop, the CAISO proposed that the RMR designations in 2008 would be based on LCR study criteria instead of Local Area Reliability Study (LARS) criteria. The input assumptions used between the two studies have been different and the CAISO proposed to forgo the LARS study and to base RMR designations on the LCR study. The CAISO stated that the LCR study has higher reliability criteria than the LARS study and that higher amounts of RMR may be required than in the past as a consequence of using a LCR study criteria for RMR designations. An intense discussion followed on the factors related to backstop alternatives.
Under the 2007 process, LSEs file preliminary Local RA filings in September and the CAISO then designates RMR units on October 1st. LSEs then procure additional units that are needed to meet its Local RAR showing in November. Under the CAISO scenario, the RMR with LARS and Local RAR with LCR criteria are the same so any units not procured by the LSEs for the September showing would be procured by RMR prior to the full RA showing. This creates an incentive for LSEs to under procure since the cost of RMR procurement by the CAISO is allocated to all LSEs. Parties expressed concern for the cost shifting that would result from an increase in the use of RMR. Several workshop participants made proposals for addressing the issue:
_ Proposal 1: The preliminary Local RA filings would be made into the final Local RA filings. LSEs would be required to procure their Local RAR as of September, so that the CAISO can execute RMR agreements only for residual needs. However, this proposal reduces the time for LSEs to procure their Local RAR.
_ Proposal 2: Maintain the existing Local RA filing schedule and the CAISO does not procure the residual Local RA units on October 1st via RMR. Instead, the CAISO would use RCST or its successor program to procure residual Local units. Currently, RCST will expire on December 31, 2007 and an extension for RCST or a successor program will require FERC approval.
_ Proposal 3: Do not change the RMR criteria, continue to use the LARS criteria for RMR designations, and the CAISO would further procure needed backstop capacity for Local RA deficiencies by using RCST. However, not changing the RMR designation study criteria results in the RA program still having 2 studies for local reliability. FERC has questioned for the CAISO's practice of using different study criteria for RMR and the RA program.
_ Proposal 4: Do not designate units for RMR again, once the unit is off an RMR agreement. This proposal would be used in conjunction with proposal two or three.
_ Proposal 5: Adjust the RMR cost allocation so that the RMR costs, that may be higher as a result of RMR reliability criteria, are billed only to the LSEs that are deficient in Local RA procurement obligations. This proposal would require the CAISO to make a change in its tariff that must be approved by FERC.
_ Proposal 6: Continue to integrate the LCR and LARS assumptions, procure the higher RMR total under existing cost allocation method, and add a surcharge for deficient LSEs. This would remove the incentives for LSEs to free ride on CAISO backstop procurement. This proposal may increase the use of RMR and the surcharge for deficient LSEs would go to the state's general fund.
_ Proposal 7: Continue to use the 2007 Local RA filing schedule, cost allocation method, LCR criteria for RMR procurement, and institute a transfer payment mechanism that would balance long and short positions, and penalize deficiencies. In D.06-06-064, the Commission considered and did not adopt a transfer payment mechanism.
_ Proposal 8: Integrate RMR/Local RAR and use the 2007 schedule. On October 1st, the CAISO would only designate units with 2007 RMR contracts that were not under RA contracts as shown in the preliminary RA filings. The CAISO would then address any deficiencies after the final Local RAR filing by using new RMR contracts, RCST, or its successor. This proposal was developed by various parties upon conclusion of the workshop.
Parties in their April 6th Track One comments are invited to comment on these Local RA/RMR proposals and provide feedback on the proposals presented in the workshop by the various parties.
7. Assembly Bill (AB) 1969
Assembly Bill 1969 was approved by the California State Legislature on September 29, 2006. AB 1969 requires electrical corporations to file tariffs providing for the purchase of renewable power from public water and wastewater treatment agencies. AB 1969 adds Section 399.20 to the Public Utilities Code to define and establish this requirement. Section 399.20, subdivision (g) provides that the physical generating capacity of an electric generation facility, as defined, shall count towards the electrical corporation's RA requirement for purposes of Public Utilities Code, Section 380.11
On February 20, 2007, CPUC staff proposed to workshop participants that the resources described by AB 1969 will count for RA purposes. In addition, CPUC staff proposed that the existing RA counting conventions are sufficient to count qualifying capacity (QC) for these resources accurately. Consensus was reached in the workshop that resources under AB 1969 should count for RA and that current counting conventions are sufficient for these resources.
The ACR and Scoping memo for Phase 2 invited any party that believes there are implementation issues related to AB 1969 that need to be addressed by the Commission through modification of the RA program should put forward its proposal for such modification in accordance with the schedule for Track One issues in Phase Two of the RA proceeding.
8. CPUC Staff Proposals for Implementation in Current RA Program
A. RA Rounding Convention for System and Local
The current policy for rounding RA requirements was adopted in D.06-06-064, "LSEs should be exempted from procurement obligations of less than 1 MW in a particular local area. In addition, RARs of 0.5 and greater should be rounded up to the next highest MW and RARs of 0.49 or lower should be rounded down to the prior MW; provided, however, that this rounding convention does not supersede the local area exemption of less than 1 MW."12
CPUC staff implemented the decision for rounding conventions in RA with two parts:
_ LSEs with a Local RAR of less than 1 MW in any one local area are exempted from procurement obligations in that local area.
_ When creating local RARs, fractional MW of 0.50 and greater should be rounded up to the next highest MW and fractional MW of 0.49 and lower should be rounded down to the prior MW; provided, however, that this rounding convention does not supersede the Local RAR exemption of RARs of less than 1 MW.
However, CPUC staff did not apply the rounding convention to System RAR and it has come to CPUC staff attention that some parties believe D.06-06-064 adopted the rounding convention for System RAR also.
CPUC staff proposed to change its implementation of rounding conventions in RA to workshop participants on February 8, 2007. After discussion, CPUC staff revised the proposal and presented it at the February 20, 2007 workshop. Workshop participants reached consensus in support of the staff implementation proposal described below.
_ Local RAR rounding unchanged.
_ For System RAR round at the level of RAR, after DR has been deducted and 15 percent planning reserve margin (PRM) has been added.
_ 1 MW minimum RAR, no LSE gets rounded down to 0 RAR.
_ Grandfather existing LSEs with less than 1 MW RAR. They will not be rounded up.
B. Qualifying Capacity (QC) for Wind Units With Less Than 3 Years Data
The QC values used in RA for wind units are based on monthly historic performance during Standard Offer 1 (SO1) Peak hours from Noon to 6:00pm using a three year rolling average. The current method was developed by participants in previous RA workshops and adopted in D. 04-10-035 and 05-10-042. The adopted methodology did not address wind units with less than three years of performance data.
CPUC staff developed a proposal and discussed it with workshop participants at the February 8th and February 20th workshops. The workshop participants reached consensus supporting the proposed resource counting convention for wind units with less than three years of data. CPUC staff will implement the proposal as outlined below.
For new units:
The average wind production factor of all units within the Transmission Access Charge (TAC) area where the unit is located will be used. For example, for a new unit in if the average wind unit production as a percent of net dependable capacity (NDC) in the TAC area during June of yr 1 was 23%, yr 2 was 22%, and yr 3 was 24%, the new unit's QC for June would be based on 23% of its NDC (23 + 22 + 24 / 3 = 23%).
For units with some operating experience, but less than 2 years of data:
The average wind production factor of all units within the TAC area where the unit is located will be used in place of the missing data in the 3 year formula. For example, if the average wind unit production in the TAC area as a percent of NDC during June of yr 1 was 23%, yr 2 was 22%, and yr 3 was 24%, and the new unit production for June was 21% of NDC for yr 3, the unit's QC for June would be 22% of its NDC (23 + 22 + 21 / 3 = 22%).
For units with at least 2 years of operating experience, but less than 3 years of data:
The unit's actual operating experience will be used. In some months the QC value will be based on 2 years of data rather than 3 years of data as established in the counting convention.
9. Other Issues Discussed in the Workshop
Although Commission's D.06-07-031 provided guidance on the required elements of standardized tradable capacity products, parties have expressed the need to develop a more standardized RA contract and more specific generator obligations in the RA program. The issue of a standardized RA contract and associated generator obligation was raised by Calpine in the February 20 and 21 workshop. Although this is not a Track One issue in Phase Two of the RA proceeding, CPUC staff requested Calpine to further explore developing a proposal with interested parties on this issue and to submit a proposal by March 22, 2007 to be used for future Commission consideration.
10. Next Steps in RA Rulemaking 05-12-013
The RA workshops addressed Track One issues in Phase Two of the RA proceeding as identified by the ACR and Scoping Memo issued by the Commission on December 22, 2006. Interested parties to the proceeding were provided the opportunity to discuss issues, proposals, and to resolve issues to the extent feasible. Parties that presented proposals during the workshops were asked to re-submit refined proposals to the RA service list by March 22, 2007. Refined proposals were to take into account comments, feedback, and recommendations made by workshop participants. Interested parties are asked to review the refined proposals for consideration in the RA proceeding.
The next steps for Track One issues are for parties to file comments to the Commission on April 6, 2007 and for parties to reply on April 20, 2007. Comments on Track One issues should include a discussion of any relevant information developed in the workshops and consideration of all proposals. Commenting parties are asked to follow the outline of this report in their comments. ALJ Wetzell intends to issue a proposed decision on Track One issues including the 2008 LCR study on May 22, 2007. Comments to the proposed decision are to be filed on June 11, 2007 and replies to comments on the proposed decision are to be filed on June 18, 2007. The current schedule is for the final decision on Track One issues in Phase Two of the RA proceeding to be on the June 21, 2007 Commission agenda.
APPENDIX A: ACRONYMS USED IN WORKSHOP REPORT
ACR-Assigned Commissioner's Ruling
ALJ-Administrative Law Judge
CAISO-California Independent System Operator
Calpine-Calpine Power America-CA, LLC
CEC-California Energy Commission
Commission-California Public Utilities Commission
CPUC Staff-California Public Utilities Commission Staff
DRA-Division of Ratepayer Advocates
ESP-Electric Service Provider
ETC-Electric Transmission Contract
FERC-Federal Energy Regulatory Commission
IOU-Investor Owned Utility
LARS-Local Area Reliability Study
LCR-Locational Capacity Requirement
LSE-Load Serving Entity
LOLP-Loss of Load Probability
MOO-Must Offer Obligation
MRTU-Market Redesign and Technology Upgrade
NDC-Net Dependable Capacity
NP26-North of Path 26
Path 26-Transmission Line Connecting Midway (PG&E) and Vincent (SCE) substations.
PG&E-Pacific Gas and Electric Company
PRM-Planning Reserve Margin
RAR-Resource Adequacy Requirement
RCST-Reliability Capacity Services Tariff
SCE-Southern California Edison Company
SDG&E-San Diego Gas & Electric Company
Sempra-Sempra Energy Solutions
SO1 Peak-Standard Offer Peak Hours
SP26-South of Path 26
TAC-Transmission Access Charge
1 Commission ACR and Scoping Memo for Phase 2, section 2.2, issued on December 22, 2006.
2 Pursuing a Probabilistic Derived LCR Presentation by Catalin Micsa of the CAISO on March 8, 2007.
3 Seasonal LCR Presentation by Catalin Micsa of the CAISO on March 8, 2007.
4 Proposed Modifications to Local RA Rules by Greg Bass of Sempra Energy on February 20, 2007.
5 Commission Decision 06-06-064, section 3.3.4, and June 29, 2006.
6 CPUC Staff Proposal Continued Aggregation of Local Areas in 2008 Presented on February 21, 2007.
7 CPUC Staff Proposal for Continued Waiver of Resource Deficiencies Presented on February 21, 2007.
8 Demand Response Resources For Local Area Reliability Presentation by SCE on March 8, 2007.
9 Demand Response Programs Presentation by PG&E on March 8, 2007.
10 Commission Decision 06-06-064, section 22.214.171.124, on June 29, 2006.
11 Commission ACR and Scoping Memo for Phase 2 issues on December 22, 2006.
12 Commission Decision D.06-06-064, Conclusion of Law, and issued on June 29, 2006.