3. Local RA for 2011

3.1. 2011 LCR Study

Decision (D.)06-06-064 determined that a study of local capacity requirements performed by the CAISO would form the basis for this Commission's local RA program. The CAISO conducts its LCR study annually, and this Commission resets local procurement obligations each year based on the CAISO's LCR determinations. As noted above, the CAISO issued its final LCR report and study results for 2011 on May 3, 2010.

The CAISO states that the assumptions, processes, and criteria used for the 2011 LCR study were discussed and recommended in a stakeholder meeting held on November 24, 2009, and that, on balance, they mirror those used in the 2007 through 2010 LCR studies. The CAISO identified and studied capacity needs for the same 10 local areas as in the previous study: Humboldt, North Coast/North Bay, Sierra, Greater Bay, Greater Fresno, Big Creek/Ventura, Los Angeles Basin, Stockton, Kern, and San Diego.

D.06-06-064 determined that the reliability level associated with Option 2 as defined in the 2007 LCR study should be applied as the basis for local procurement obligations for that year. The Commission stated that "[w]hile we expect to apply Option 2 in future years in the absence of compelling information demonstrating that the risks of a lesser reliability level can reasonably be assumed, we nevertheless leave for further consideration in this proceeding the appropriate reliability level for Local [resource adequacy requirements] for 2008 and beyond." (D.06-06-064 at 21.) Each of the RA LCR decisions in the last three years adopted Option 2 as recommended by the CAISO for 2008 through 2010 local procurement obligations. There is no evidence or recommendation before us suggesting that assumption of the reduced reliability associated with Option 1 is reasonable for 2010. We therefore, affirm the continued application of Option 2 to establish local procurement obligations for 2011.

The 2010 and 2011 summary tables in the 2011 LCR report, copied below, show that for all ten areas combined, the total LCR associated with reliability Category C increased from 27,727 megawatts (MW) in 2010 to 28,058 MW in 2011. The existing capacity needed increased from 27,075 MW in 2010 to 27,094 MW in 2011. LCR needs decreased in the North Coast/North Bay, Sierra, Fresno, Big Creek/Ventura and San Diego Areas due to downward trends for load. LCR needs increased slightly in the Humboldt area due to new Humboldt Bay Power Plant configuration, in the Greater Bay due to the Portrero Power Plant retirement, in Kern due to load growth and in the Los Angeles (LA) Basin due to load growth and permanent retirement of the Antelope-Mesa Cal 230 kilovolt (kV) line. The Stockton area LCR needs are steady.

2011 Local Capacity Requirements

	Qualifying Capacity			2011 LCR Need Based on Category B			2011 LCR Need Based on Category C with operating procedure
Local Area Name	QF/ Muni (MW)	Market (MW)	Total (MW)	Existing Capacity Needed	Deficiency	Total (MW)	Existing Capacity Needed	Deficiency	Total (MW)
Humboldt	57	166	223	147	0	147	188	17	205
North Coast / North Bay	133	728	861	734	0	734	734	0	734
Sierra	1057	759	1816	1330	313	1643	1510	572	2082
Stockton	267	259	526	374	0	374	459	223	682
Greater Bay	1210	5296	6506	4036	0	4036	4804	74	4878
Greater Fresno	485	2434	2919	2200	0	2200	2444	4	2448
Kern	699	9	708	243	0	243	434	13	447
LA Basin	4206	8103	12309	10589	0	10589	10589	0	10589
Big Creek/ Ventura	1196	4110	5306	2786	0	2786	2786	0	2786
San Diego	194	3227	3421	3146	0	3146	3146	61	3207
Total	9504	25091	34595	25585	313	25898	27094	964	28058

2010 Local Capacity Requirements

	Qualifying Capacity			2010 LCR Need Based on Category B			2010 LCR Need Based on Category C with operating procedure
Local Area Name	QF/ Muni (MW)	Market (MW)	Total (MW)	Existing Capacity Needed	Deficiency	Total (MW)	Existing Capacity Needed	Deficiency	Total (MW)
Humboldt	48	135	183	176	0	176	176	0	176
North Coast / North Bay	149	736	885	787	0	787	787	3	790
Sierra	1066	769	1835	1133	102	1235	1717	385	2102
Stockton	229	266	495	357	0	357	432	249	681
Greater Bay	1096	5608	6704	4224	0	4224	4651	0	4651
Greater Fresno	502	2439	2941	2310	0	2310	2640	0	2640
Kern	656	9	665	187	0	187	403	1	404
LA Basin	3918	8212	12130	9735	0	9735	9735	0	9735
Big Creek/ Ventura	947	4146	5093	3212	0	3212	3334	0	3334
San Diego	205	3502	3707	3200	0	3200	3200	14	3214
Total	8816	25822	34638	25321	102	25423	27075	652	27727

The comments reveal no disagreement with CAISO's LCR determinations for 2011. As we noted in D.09-06-028, it appears that past efforts towards greater transparency and opportunity for participation in the LCR study process have paid off in significant part. We determine that the CAISO's final 2011 LCR study should be approved as the basis for establishing local procurement obligations for 2011 applicable to Commission-jurisdictional LSEs.

AReM notes that since the CAISO issued the first LCR calculation in September 2005, LCRs have increased by about 20% for the CAISO grid statewide. The number of deficient areas has also increased significantly. AReM points out that for 2011, only three LCRs are not deficient: North Coast/North Bay, LA Basin and Big Creek/Ventura. Even accounting for the addition of the Big Creek/Ventura Local Capacity Area (LCA) in the 2008 compliance year, which added 3,700 MW to the LCRs, AReM asserts that the trend is, at best, steady state. Further, while California is experiencing a major recession beginning in 2008, AReM shows that the LCRs are still increasing, by 1.2% from 2010 to 2011. AReM requests that the Commission consider improvements to the annual LCR process in Phase 2 with the objective to reverse this trend and begin to reduce the MWs of LCRs and number of LCAs when cost-effective, therefore, lowering costs for California's consumers.

SDG&E contends the South Bay power plant is not needed to satisfy local capacity requirements in the San Diego area in 2011 and that South Bay retirement will also advance important environmental goals. SDG&E claims that retiring a resource like South Bay, which SDG&E claims is both environmentally harmful and not necessary for reliability purposes in light of the CAISO's 2011 LCR study, would further California's important water resource goals. SDG&E also argues that CAISO should undertake a separate, additional LCR study to determine seasonal local capacity obligations.

We intend to work with CAISO and other stakeholders to discuss the issues raised by AReM and SDG&E and determine if these concerns can be accommodated. The Administrative Law Judge (ALJ) will determine if these issues should be added to the scope of the proceeding in Phase 2.

3.2. Local Procurement Obligations for 2011

3.2.1. Continuation of the Local RA Program

The RA program was first implemented with the 2006 compliance year for "system" RA requirements. "Local" RA procurement obligations were first implemented the following year. Even though several decisions over the past five years have largely defined the RA program, it remains necessary and appropriate to have a procedural mechanism in place to address the ongoing needs of the program. As the Commission stated in a June 2007 RA decision:

"While the nature of the future RA program and the associate
procedural requirements cannot be fixed at this time, it is clear that there is an ongoing need for a procedural vehicle to address both modifications and improvements to the RA program as well as routine administrative (but not ministerial) matters that are not delegable to staff. Among other things, the local RA program component requires annual approval of [local capacity requirements (LCRs)] based on the [California Independent System Operator's (CAISO's)] LCR studies. For the near and intermediate term, we see a need for annual proceedings for these purposes." (D.07-06-029
at 52.)

D.06-06-064 adopted a framework for local RA and established local procurement obligations for 2007 only. D.07-06-029, D.08-06-031 and D.09-06-028 established local procurement obligations for 2008, 2009 and 2010, respectively. We intend that local RA program and associated regulatory requirements adopted in those decisions shall be continued in effect for 2011, subject to the 2011 LCRs and procurement obligations adopted by this decision.

In previous decisions, we delegated ministerial aspects of RA program administration to the Commission's Energy Division. The Energy Division should implement the local RA program for 2010 in accordance with the adopted policies.

3.2.2. Local Resource Adequacy True-ups

The resource adequacy program developed by the Commission provides local resource adequacy obligations for LSEs for a 12-month compliance period. However, the program currently does not require LSEs to true-up their obligations within the compliance year. It is possible that true-ups could be required for changes in load within the compliance year for various reasons; in particular, the re-opening of direct access in 2010 (discussed below) makes it more likely that some LSEs will have significantly different levels of load at times throughout the compliance year. One concern is that the result of not having a local true-up mechanism is that the local resource adequacy product loses its premium value after the year-ahead showing, creating financial risks for LSEs which lose customers and a possible competitive edge for new entrants.

Under the current practice, each LSE is obligated to meet its local resource adequacy requirement (RAR) annually by procuring local RA capacity based on its load ratio share. The load ratio share is the LSE's annual forecasted coincident peak load, adjusted by the California Energy Commission (CEC), divided by the total forecasted coincident peak load in the LSE's utility service territory. This method requires an LSE to procure the same amount of local RA capacity for every month of the forecast year, based on the peak month (August) local requirement. Until recently, there has been no process for adjusting an LSE's local RA obligation to account for or true-up load migration during the compliance period.

Adopting a local true up mechanism into the RA program was discussed in R.08-01-025, the predecessor to this Rulemaking. However, the Commission did not adopt a proposed local true up mechanism but instead deferred implementation to the 2011 compliance year and this proceeding.

Pursuant to Senate Bill (SB) 695 (Stats. 2009, ch. 337), the Commission reopened Direct Access (DA) in D.10-03-022. The decision states: "Effective April 11, 2010, all qualifying customers will be eligible to take DA service, up to the new maximum cap subject to the conditions as set forth herein. The increased DA allowances shall be phased in over a four-year period, subject to annual caps in the maximum DA increase allowed each year."¹ Additionally, D.10-03-022 states: "SB 695 requires the Commission to ensure that other providers of electricity in California are subject to the same procurement-related requirements that apply to the IOUs, including RARs, renewables portfolio standards, and greenhouse gas emission reductions."²

With the reopening of Direct Access, the expected load migration between LSEs throughout the year will have some effect on the local obligation of the participating LSEs. In order to track the local RA obligation and ensure that that all service providers are subject to the same RA treatment, D.10-03-022 adopted a local true-up mechanism for 2010.³ This mechanism applies for 2010 only.

SCE notes that D.10-03-022 allows for local attributes unbundling as part of the partial reopening of DA. SCE believes that the administratively determined price established in this decision is "appropriate for the initial partial reopening of direct access, and will serve to smooth the transition period for the market"⁴ SCE notes that this established price should not be maintained and the market should be allowed to establish the most efficient outcome.

Calpine suggests that the transfer payment adopted in D.10-03-022 not be a part of the rules adopted for the 2011 RA compliance period. In particular, Calpine requests that the option to meet local RA obligations through a
$24/kilowatt (kW)-year administrative transfer payment not continue beyond 2010. Calpine objects to this transfer payment because it is unclear that the amount represents an appropriate value for RA in all local locations.

As we just recently adopted the local RA true-up for 2010 and there is no compelling reason to change it at this time, we will continue the local RA true-up method adopted in D.10-03-022 for the rest of 2010 (and until it is superseded by a new method) without revision. For 2011 and beyond, parties have proposed different local true-up methods. These are discussed below.

3.2.2.1. The "True-Up Approach" and "Reallocation Method" Proposals

SES and TURN filed separate local true-up proposals that have been revised into one and refined though the course of this proceeding. The initial proposal will be called the "True-Up Approach." The True-Up Approach is based on transferring specific shares of local requirements on individual customers using that customer's local-to-peak ratio and coincident peak demand.

The SES/TURN True-Up Approach uses a Local-to-Peak Ratio (LPR) percentage approach which is also the adopted method in the recent DA decision, D.10-03-022. Like the 2010 local true up adopted in D.10-03-022, the LPRs would be calculated by the Energy Division.

The next step is to calculate the Customer Local Obligation (CLO) associated with each migrating customer. As customers migrate, the load-losing LSE would calculate the CLO associated with the migrating customer and report it to the CEC and Energy Division. The Energy Division would then match the load migration between the losing and gaining LSEs and then require the
load-gaining LSE to procure additional local RA capacity. The process would happen only once a year beginning in early February.

To address the issue of materiality, SES and TURN would limit the size of the load migration to 5 MW blocks of capacity. Additionally, to handle local RA capacity liquidity concerns, they propose to aggregate the local RA areas by investor-owned utility (IOU) service territory. They argue that this will provide more flexibility for LSEs that are buying and selling local RA capacity. Since the San Diego local area is known to be resource constrained, a special rule for that area may be needed. SES/TURN proposes a rule that would allow the transfer payment mechanism used in 2010 to continue for only the SDG&E service area. Lastly due to asymmetry, the three IOUs would be required to sell their excess local RA capacity periodically through the Request for Offer (RFO) process.

SES and TURN propose a decision point in either the end of the 2010 or the beginning of 2011, to determine "whether a sufficient liquid, tradable local RA capacity (i.e., Standard Capacity Product) has successfully emerged to facilitate the commercial aspects associated with a local RA capacity True-Up."⁵ A decision at this point would allow the Commission the opportunity to assess whether the default transfer payment mechanism that was adopted in Rulemaking (R.)07-05-025 should continue for the 2011 compliance period.

In addition to the True-Up Approach, SES and TURN proposed a second idea, which will be called the "Reallocation Method." The Reallocation Method is based on reallocating the local RA obligation to LSEs using an LSE's updated August coincident peak load forecast. The Reallocation Proposal "builds directly on the current processes being employed by the CEC and Energy Division staff for allocation in the year-ahead local RA capacity obligation, in approving the monthly adjustments to LSEs' load forecasts for System RA capacity compliance purposes and in calculation of CAM [cost allocation mechanism] and RMR [reliability must-run] allocations."⁶

The Reallocation Method has LSEs submit a revised coincident peak demand forecast for August 2011 in April 2011. This forecast is used as a means to recalculate and redistribute any local RA obligation that may have migrated. The LSEs would receive their local RA reallocation in May 2011 and would have 30 days to procure any additional local RA capacity. The first local true-up would be made June 1, 2011 (pre-summer true up). This same cycle would then begin again in August 2011 with the revised forecast due, followed by the reallocation of their local RAR in September, and followed by a second showing on October 1, 2011 (post summer true up).

PG&E supports a modified version of the True-Up Approach. PG&E argues the 5 MW threshold for reporting load migration should not be adopted because such a threshold could effectively penalize the LSE losing load by not compensating it for the costs of local RA now being used to meet the needs of the LSE gaining the load. Additionally, PG&E proposes to modify the proposal to adopt monthly payments. The primary concern that PG&E has with the reallocation method is that it considers changes to local RA only two times for the year.

SCE recommends the Commission not adopt the Reallocation Method because it does not provide any detail as to how the LSEs' revised August coincident peak demand forecasts will be validated and policed for accuracy. Additionally, SCE argues that the Reallocation Method assumes a "best estimate" that does not necessarily account for all customers. SCE is also concerned that allowing only a single month to procure additional local RA capacity could result in additional market power issues associated with the urgency of completing the transaction.

SCE supports a modified version of the True-Up Approach that allows for the unbundling of the local attribute from system RA capacity. SCE believes that by disaggregating the local attribute it will increase liquidity in the local RA capacity market. Additionally SCE interprets D.10-03-022 as unbundling the local attribute subject to an administratively determined price.

SCE does not support a decision point in late 2010 or early 2011 to assess the default transfer payment. SCE requests the Commission not adopt the default transfer payment for 2011, stating: "Effectively, the default transfer payment creates a free option for local capacity buyers. Allowing the market to establish prices will result in the most efficient outcome that will be beneficial to both buyers and sellers alike."⁷

AReM disagrees that SCE's modification will create a more liquid market for RA. AReM is concerned that unbundling and sales of the local attribute would undermine the development of local RA capacity market. AReM supports the True-Up Approach with a decision point in late 2010 to conclude if a liquid, tradable capacity market exists.

TURN requests that unbundling of the local attributes from local capacity be deferred until more experience in this area is gained. DRA supports the
True-Up Approach, and unbundling of the local attribute. SDG&E supports the True-Up Approach.

Calpine supports the True-Up Approach but does not support the transfer payment section established in the DA decision. They request that if a transfer payment mechanism is maintained then additional rules need to be created to monitor its use.

3.2.2.2. Discussion

The local true up mechanism adopted in the DA decision is mostly consistent with the True-up Approach proposed in this proceeding. The main difference between the two is that the true up mechanism in D.10-03-022 for 2010 adopts a default transfer payment price for local RA:

"The default transfer payment would provide an administrative price for the transfer of local RA credits of $24 per kW-year. This amount is intended to reflect only the "premium" value of local RA capacity over System RA capacity, since the LSEs acquiring new load would still be purchasing any increased amount of System RA capacity required to be shown in its monthly System RA filing under the current RA load migration rules. Rather than a flat $2.00 per kW-month, the monthly prices would be "shaped" to reflect the fact that RA capacity is most valuable during the peak summer months. This shaping would spread the $24 over the months of the year based on the same factors (shown below) that were used to allocate capacity payments under the CAISO's former Reliability Capacity Services Tariff program across the 12 months of the year. In mathematical terms, the transfer payment would be determined as follows:

CLO x $24/kW-yr x Shaping Factor for remaining months of 2010."⁸

To this point, parties have commented mostly on the True-Up Approach, and less on the Reallocation Method. We will not adopt either the True-Up Approach or the Reallocation Method at this time, but will take further comments after this decision.

We are not convinced at this time that the True-Up Approach should be adopted. Elements of the proposal have raised concern with many parties. These concerns include the use of a transfer price, the unbundling of the local attribute, the forecast method being employed, the 5 MW threshold of load migration in each IOU territory, the aggregation of areas by IOU service territory, and the treatment of SDG&E. These concerns would be best answered with experience from the current local true method being used. Therefore, before adopting a local true up method for 2011, we wish to consider the experience gained in 2010.

We also wish to consider further the Reallocation Method. The key advantage of the Reallocation Method appears to be that it builds on the current method employed by the CEC and Energy Division to reallocate CAM and RMR allocations as well as to adjust monthly system requirements for load migrations. Adopting the Reallocation Method, or something similar, could alleviate the need to oversee the transfer payment mechanism and problems associated with monitoring individual customer movements and transactions. This would provide all parties with less of an administrative burden associated with a new process. On the other hand, the Reallocation Method does not provide the LSEs with the exact local RA capacity true-up obligation until after the CEC and Energy Division recalculate reallocations. Further, it also only gives LSEs 30 days to procure any additional need local RA capacity.

Some parties propose a decision process later this year to revisit the adopted local true up methodology based on experience with the first two local RA true up filings during 2010. We agree that the recently adopted local true up process presents an opportunity to evaluate the adopted process. We can then take what we have learned from the local true-up process in 2010 and make a decision for 2011 based on the record and that experience.

We accept TURN and AReM's suggestion to re-evaluate the 2010 local true up during a decision phase later this year, once there is sufficient experience gathered with the local RA true up mechanism adopted in the DA proceeding. However, in light of our plans to revisit this issue later in 2010, once experience has been gathered with the true-up mechanism adopted by D.10-03-022, we encourage parties to give serious consideration to the Reallocation Method.

3.2.3. Aggregation of Local Areas

To address supplier market power concern, D.06-06-064 established an approach for aggregation of certain local area for 2007. After determining each LSE's local RA obligation in each local area, the Commission 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 RA compliance. These are known as the "other PG&E" local areas.

Given the local resource constraints identified by the CAISO in the "other PG&E" local areas, we conclude it is best to keep the local areas aggregated for 2011. One of the purposes of the LCR studies is to identify the local constraints in the coming year. Given the 2011 LCR results of the "other PG&E "areas, there still are a limited amount of resources in those areas. At this time there is still a need to keep the "other PG&E" areas aggregated for market power concerns. However, this decision is linked to the outcome of the LCR study which is done annually and runs simultaneously with the RA proceeding. Therefore, we reject AReM's proposal, to make this aggregation permanent, and will revisit the aggregation of the "other PG&E" local areas annually with the results of the LCR study.

3.2.4. Local Area Deficiency

The Commission in previous resource adequacy decisions (See, e.g.
D.06-06-064 at 21-22) provided that an LSE cannot be required to procure capacity that does not exist, in situations where the local area resource need is higher than existing capacity. The Scoping Memo determined that continuation of this "blanket waiver" should be a Phase 1 topic.

AReM proposes that the "blanket waiver" be made permanent so that

we do not have to revisit it every year. We do not see a situation in the immediate future where there will be no need for this waiver. We therefore adopt AReMs proposal to make the "blanket waiver" a permanent part of the RA program for 2011 and onward, but reserve the right to revisit it if needed.

¹ D.10-03-022 at 2.

² D.10-03-022 at 25.

³ D.10-03-022 Appendix 3.

⁴ SCE comments at 16.

⁵ Joint Phase 1Comments of SES and TURN at 3.

⁶ Semi-Annual Local RA Capacity Reallocation to Account for Load Migration Proposal at 1.

⁷ SCE reply comments at 6.

⁸ D.10-03-022 Appendix 3.