4. Local RA for 2008 and Beyond
4.1. 2008 LCR Study
In D.06-06-064, the Commission determined that a study of local capacity requirements conducted by the CAISO would form the basis for this Commission's Local RA program. As noted above, the CAISO published its 2008 LCR study on March 9, 2007. Following a March 21, 2007 stakeholder meeting, it filed an updated study on April 4, 2007. In Section 4.1 of this decision we address the extent to which the 2008 LCR study should be approved as the basis for local procurement obligations to be met by Commission-jurisdictional LSEs for the 2008 RA compliance year. We also address the need for improvements to the LCR study process.
The CAISO states that the assumptions, processes, and criteria used for the 2008 LCR study mirror those used in the Commission-approved 2007 study. The overall LCR trended upward from 2007 to 2008 due to load growth. The LCR for the Greater Bay Area was reduced from 4,771 MW to 4,688 MW (using LCRs associated with the Category C level of reliability) due to installation of the Vaca-Dixon 500/230 kilovolt (kV) transformer. The LCR for the Los Angeles (LA) Basin increased from 8,843 MW to 10,130 MW based largely on an evaluation of the South-of-Lugo operational path rating that was not available for the 2007 study. In addition, a new local area was identified-the Big Creek/Ventura area with an LCR of 3,658 MW. The total of LCRs for all areas increased by 22%, from 22,934 to 28,030 MW.
The magnitude of increases in LCRs, particularly in Southern California, led to substantial concern regarding the study and how its results should be translated into LSE procurement obligations. AReM recommends, among other things, that year-to-year increases in LCRs be capped at 10%. Drawing on the capping approach espoused by AReM, Aglet recommends a cap of 5%. SCE contends that the 2008 LCR study inappropriately used outages of intertie transmission lines to define local needs in both the Big Creek/Ventura Area and the LA Basin Area. SCE believes the increases in the amount of local generation required are therefore improper. SCE recommends that the LCR study be modified to recognize that San Diego area generation relieves South-of-Lugo loading. SCE further recommends that the LCR for the Big Creek/Ventura Area be defined by outages within the area, not on the contingencies identified by the CAISO. If the Commission approves the establishment of the Big Creek/Ventura Area, SCE believes that the Commission should either (1) not establish a local procurement requirement for that area based on the 2008 LCR study5 or (2) if it does establish such a procurement obligation, explicitly waive penalties for LSEs that fail to meet their local requirement for the Big Creek/Ventura Area.
The 2007 to 2008 LCR increase for the LA Basin Area appears large, but it is explained by a combination of load growth and an up-to-date evaluation of the effect of transmission upgrades on the South-of-Lugo operational path rating. The CAISO notes that if accurate data had been available for the 2007 study, the LA Basin Area LCR for 2007 would have been 9,923 MW, not 8,843 MW. Stated differently, the 2007 LCR study understated LA Basin Area requirements due to the lack of a current evaluation of the path rating. That does not render the 2008 study inaccurate or unreasonable, however. On the contrary, now that more current information regarding the path rating is available, it would be unreasonable to adhere to an understated LCR determination that was made a year ago in connection with the 2007 study.
SCE's objection to the establishment of the Big Creek/Ventura Area is based on the contention that the CAISO has changed the LCR study approach by using the contingency of an intertie outage. This objection does not appear to be well-founded, since the potential universe of transmission outages that may be considered for purposes of identifying the most severe contingency has consistently encompassed any transmission line, including interties. We find no substantial grounds for invalidating the LCR study, and therefore find that the Big Creek/Ventura Area should be established without a phase-in or blanket penalty waivers as proposed by SCE. No party has shown that the existing waiver procedure that was adopted by D.06-06-064 is inadequate to address LSEs' concerns about potential market power, if any, that may be associated with the Big Creek/Ventura Area. LSEs have been on notice since the March 2007 release of the 2008 LCR study that CAISO is proposing to establish the new area. As the CAISO notes, the implementation schedule for procurement obligations arising from the newly identified area is comparable to the schedule that was followed when local procurement obligations were first established last year pursuant to D.06-06-064. Similarly, we find inadequate justification for capping the year-to-year LCR increases as suggested by AReM and Aglet.
The LCR study is based on 1-in-10 year summer peak load forecasts. Aglet believes that the use of 1-in-10 forecasts leads to a high level of RA procurement that is not cost-effective. Aglet proposes that we approve local procurement obligations based on 1-in-5 forecasts. Using (1) "willingness to pay" data from a value-of-service study prepared for PG&E, (2) assumptions about RA resource costs drawn from the CAISO's Reliability Cost Services Tariff, and (3) an estimate that the 1-in-10 forecast leads to the procurement of an additional 364 MW by PG&E compared to a 1-in-5 standard, Aglet calculated benefit/cost ratios for various classes of PG&E customers. Aglet concluded that use of a 1-in-10 standard is not cost-effective for PG&E's residential customers unless resource costs are at or below $37/kW-year.
The PG&E specific value-of-service analysis before us relies on assumptions that may not be accurate or reliable for purposes of local RA.6 For example, it assumes that a one MW reduction in LSE procurement will be realized for every MW reduction in LCR. That may not be a supportable assumption in light of the fact that local capacity procurement also counts towards system RA obligations. In addition, Aglet's benefit/cost conclusions at best apply to PG&E's residential customers. For all other classes of PG&E ratepayers the calculations show high, positive benefit/cost ratios associated with the higher reliability standard.
Even if we did accept the assumptions and analysis behind Aglet's conclusions, we would then need to weigh the apparent residential customer interest in reduced reliability against the interest of other customers in a greater level of reliability. This is because current system design does not permit the CAISO and the utilities to operate the electric system to differentiated reliability levels depending on customer class. Aglet's analysis does not provide any basis for making such a determination. In summary, we find no reason for departing from the use of 1-in-10 peak load forecasts for determining local reliability capacity needs.
In the following section we describe actions that are intended to address ongoing concerns about transparency and timing of CAISO's LCR study process. Notwithstanding the need for process improvements, we are persuaded that the 2008 LCR study should be approved as the basis for establishing local procurement obligations for 2008 applicable to Commission-jurisdictional LSEs. D.06-06-064 adopted a framework for Local RA and established local procurement obligations for 2007 only. We clarify here that the Local RA program and associated regulatory requirements adopted in D.06-06-064 are continued in effect for 2008, subject to the modifications and the 2008 LCRs adopted by this decision.
In D.06-06-064, the Commission determined that a level of reliability associated with "Option 2," which was based on "Category C" criteria as defined in the 2007 LCR study, should be applied as the basis for local procurement obligations.7 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 RAR for 2008 and beyond." (D.06-06-064, p. 21.)
The CAISO explains that the LCRs determined for the various local areas that are based on Option 1/Category B reliability level implicitly rely on load interruption as the only means of meeting any Applicable Reliability Criteria beyond the loss of a single transmission element. The CAISO states that Option 2 is the local capacity level that it needs to reliably operate the grid per NERC, WECC, and CAISO standards. The CAISO therefore proposes that the Commission approve the Option 2/Category C reliability level and the associated LCRs. No party has submitted compelling information that would cause us to depart from the standard approved for 2007 and recommended by the CAISO for 2008. We therefore approve and adopt the Option 2/Category C reliability standard for setting local procurement obligations.
On May 10, 2007, the CDWR filed a motion for acceptance of late-filed comments to note concerns with the LCR study process and to advise the Commission of "apparent factual errors" in the 2008 LCR study. In particular, the CDWR believes that the CAISO erroneously identified CDWR pump load located in the Big Creek/Ventura Area as part of the load to be subject to local procurement requirements. CDWR states that the load is controllable and should not be included as firm load. The ALJ granted the motion in an e-mail ruling dated May 14, 2007.
CDWR has raised an important question about the appropriate treatment of pump load in the LCR study process that warrants investigation for future LCR studies. It may be the case that pump load should not be treated the same as tariffed interruptible DR programs, which programs generally qualify as resources under the RA program.8 It does not appear, however, that this issue was adequately and timely developed such that a modification to the 2008 LCR is justified at this time. On the other hand, it may be appropriate for the CAISO and parties to consider the CDWR's concerns in the supplemental LCR review process described below. To the extent that pump load is reflected in the Big LCR for a local area but is also controllable or interruptible and therefore available as a DR resource, it may be feasible for CDWR and other agencies to enter into appropriate arrangements with LSEs for their use of this load in fulfillment of procurement obligations for the area. This topic should be included among those taken up in the workshop on LCR study improvement described in the following section.
Some parties have suggested that we allow for the identification of 2008 LCR study refinements and corrections as well as operational solutions that might result in reduced LCRs without jeopardizing reliability. In view of both the desirability of ensuring that LCRs are based on accurate and current data and the limited time available for, such LCR revisions, we will approve a supplemental LCR study review procedure based on that adopted in D.06-06-064 in connection with the 2007 LCR study. Accordingly, while we adopt the CAISO's 2008 LCR study for purposes of establishing local procurement obligations in the coming year, we will authorize Energy Division to calculate and establish reduced local procurement obligations, if any, that might result from further LCR study analysis, either as determined by or agreed to by the CAISO staff. This is a ministerial determination, and the Energy Division is not authorized to approve LCR study adjustments or revisions that increase any LSE procurement obligation or that use a reliability standard lower than that approved herein. Notice of the operational solutions and study corrections approved by the CAISO, if any, should be provided to parties and stakeholders to the extent permitted by confidentiality protocols.
Staff analysis has shown that the LCR study did not use CEC-approved load forecast data for the San Diego local area. We therefore request the CAISO to recalculate the San Diego Area LCR using the correct data. We realize this adjustment may result in an increased LCR for that area, and hereby approve such increase.
For the 2008 LCR study, the CAISO formed the LCR Study Advisory Group (LSAG), a representative cross-section of stakeholders technically qualified to assess the issues related to the study and to recommend changes where needed. Notwithstanding this generally positive development, several parties have expressed concerns about the 2008 LCR study process. CMUA notes, for example, that by the time the LSAG began work in earnest, it was considered too late to review changes to the methodology in time for the 2008 RA cycle.9 CMUA, whose members were among active CMAG participants, believes there needs to be better coordination of the CAISO study cycle consistent with CAISO tariff requirements and the Commission's RA schedule. CDWR faults the study's lack of transparency in connection with the asserted failure to disclose study inputs and assumptions. PG&E observes that "time and resource constraints on the CAISO have been detrimental to the process of developing a clearly understood, verifiable study in which assumptions and judgment calls are sufficiently transparent to assure consistency with the Commission's principles and expectations." (PG&E Comments, p. 4.) PG&E goes on to state that for 2009 and beyond, a more deliberative process is needed that is consistent with Grid Planning studies, subject to checks and balances, and designed for greater stability. The CAISO itself acknowledges in its reply comments that study improvements must still be made.
It is clear that concerns about timing and transparency issues continue to vex the LCR study process. Stakeholders remain uncertain regarding study inputs and assumptions, and opportunities for meaningful dialogue seem limited. In view of the tight schedule of the RA compliance cycle, LSEs face significant if not severe constraints on their ability to plan their procurement activities. This Commission's own decisionmaking process is also impacted by the schedule. There is simply too little time between the publication of the LCR study report in March and the issuance of a Commission decision in June to enable the careful and methodical review and refinement that the study warrants.
Improvements to the LCR study process for 2009 and beyond (including the schedule) are both needed and achievable. It would be helpful for the CAISO to issue the planned study assumptions for comment prior to conducting the study. More generally, PG&E's and TURN's proposals for improving the LCR process merit careful consideration.10 We note that the CAISO shares the objective of integrating the LCR and grid planning processes, and we agree this objective should be pursued. In addition, stakeholders would clearly benefit from the CAISO's multi-year assessment of LCRs taking into account known and planned transmission system developments. As PG&E points out, a long-term forecast of LCRs may be essential for both transmission planning and generation procurement activities. Also, as AReM points out in its comments on the proposed decision, LSEs would benefit from early notice (e.g., two years) that the CAISO has identified a new load pocket.
We ask our Energy Division to collaborate with the CAISO in developing proposals for LCR study process improvements and to convene a workshop to be held in the summer of 2007. The workshop should address, at a minimum, the need for timely submission of operating solutions, opportunities for stakeholders to review and discuss LCR study input assumptions and methodology prior to the actual conducting of the study, and opportunities for stakeholders to provide input on the draft LCR study well in advance of the final LCR study report. Following such workshop, we anticipate the issuance of an Assigned Commissioner's ruling directing the implementation of process improvements that have been identified through such collaboration and workshops.
4.2. Probabilistic Analysis in LCR Studies
In D.06-06-064 the Commission indicated support for using a probabilistic approach to the LCR study as it could lead to more economically efficient decisions regarding the capacity that LSEs must procure at any particular location. The Commission asked the CAISO and other parties to take all reasonable steps to implement this approach as soon as practicable. Recognizing that the CAISO will need to take a lead role in moving to a probabilistic approach for future LCR studies, the Phase 2 Scoping Memo asked the CAISO to present (1) a discussion of how probabilistic analysis can be incorporated into future LCR studies, (2) its recommendations on the steps to be taken by the CAISO, and (3) its recommendation as to the actions that the Commission should take on this topic.
The CAISO made its presentation for pursuing a probabilistic LCR study in the Track 1 workshops. The CAISO estimated that from the granting of initial funding for this study and gaining commitment from CAISO management, a proposed probabilistic study can be completed for consideration for implementation in the RA program within two years. The study would determine the Loss of Load Probability (LOLP) for each Local Area in RA, which could be used in setting future Local RAR. Milestones identified by the CAISO included adopting an 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 LSAG to address the technical issues involved with a LOLP study.
Parties generally support the Commission's and the CAISO's vision for incorporating probabilistic analysis into the LCR study process, although there are some questions regarding the priority of the undertaking. For its part, the CAISO has indicated its commitment to develop and integrate LOLP into the grid planning process for potential application in the RA program, consistent with strictures of competing priorities.
We remain supportive of a transition to probabilistic analysis for future LCR studies, and are gratified by general stakeholder support and the CAISO's commitment to move forward within the limits of its resources. As with the LCR study process generally, the process of incorporating LOLP analysis into the LCR study should be as open to stakeholder participation. There may be an appropriate role for the LSAG, but the opportunity for meaningful stakeholder participation should not be limited to subject matter experts. Because this is expected to be a two-year undertaking, and the start date has not yet been fixed, we intend to monitor progress toward achievement of the objective of probabilistic LCR analysis as the underpinning for Local RA. We therefore request that the CAISO submit periodic status/progress reports, not less frequently than bi-monthly, to our Energy Division and serve those reports on the service list for this proceeding or successor proceeding that addresses RA.
4.3. Seasonal LCR Analysis
Because 1-in-10 summer peak loads do not occur year round, parties have suggested that the CAISO calculate seasonal variations in the LCR. In theory, this would allow reduced local procurement obligations during times of the year when loads are lower. AReM contends that the current requirement to meet a peak requirement on a year-round basis is an onerous burden for LSEs, and particularly so for ESPs. AReM notes that some ESPs have local procurement requirements that nearly exceed their System RAR in some off-peak months. PG&E shares the view that the seasonal difference in LCRs could be very significant, and that for many areas there may be no winter requirements at all. System-wide, PG&E notes, peak loads during the winter are over 30% lower than summer peak loads. Also, most transmission line winter ratings are 25%-40% higher than summer ratings.
The CAISO, which opposes further consideration of a seasonal LCR at this time, identified several technical hurdles, operational impacts, and programmatic issues that would be associated with a seasonal LCR study. The 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 peak. Operational impacts identified by the CAISO include potential effects on the CAISO's outage coordination process and 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. Programmatic issues identified by the CAISO include the need for reevaluation of resource deliverability and import capability, and a greater administrative burden on LSEs.
We concur with the CAISO's assessment that we lack sufficient evidence to conclude that the potential benefits of a seasonal LCR approach outweigh the likely costs. Under the circumstances, and also in light of the fact that the current LCR study process is already time- and resource-intensive, we are hesitant to push forward with a seasonal LCR policy at this time. We are open to demonstrations of cost-effectiveness of seasonal LCR in future RA proceedings. We also believe that PG&E's recommendation for targeted pilot studies warrants careful consideration by the CAISO and stakeholders. While we are not prepared to order such pilot studies on the record before us, we welcome proposals for pilot studies, which may be taken up in the previously described summer 2007 workshop on improving the LCR study process.
4.4. Load Migration
Currently, LSEs must procure 100% of their Local RAR on a year-ahead basis. The Phase 2 Scoping Memo found that it would be reasonable to receive proposals for a monthly compliance filing process for Local RA to permit or require LSEs to reflect load migration impacts.
In response to the Phase 2 Scoping Memo's call for pre-workshop proposals on Track 1 issues, several parties commented on the pros and cons of monthly true-ups of local RAR to account for load migration without offering proposals for their implementation.11 Sempra Global offered a proposal suggesting that protocols for Local RA be as similar as possible as System RA, including monthly true-ups. A key component of the Sempra Global proposal was that the Local RAR for each LSE should be expressed as the ratio of the total Local RAR in the utility service area to the total System RAR in that service area. Sempra Global suggested that using a percentage rather than a flat MW value would allow for variations in monthly peaks and more accurate true-ups.
The workshop discussions led to general consensus that a MW allocation would be better than a percentage allocation, but several questions remained about the need for numerical examples of how such an approach would actually work. Upon request and direction of the Energy Division, SES e-mailed a revised proposal for monthly true-ups on March 22, 2007. The latest proposal provides that when the adjusted monthly forecast exceeds the year-ahead, peak-month load forecasts, there would be an LSE obligation to procure additional Local RA capacity. When the monthly true-up forecast is below the year-ahead forecast for that month, the LSE would be permitted to adjust its Local RA obligation downward according to a "baseline ratio."
The comments reveal that significant problems remain in designing a monthly true-up mechanism, and that the latest proposal from SES is not ready for adoption. As TURN notes, the proposal appears asymmetric with respect to when it would allow for increases and decreases in the LCRs for particular LSEs. Based on factual scenarios in examples in the proposal, an LSE that loses 500 MW of load in May of the compliance year would see its LCR reduced by 250 MW for every remaining month of the year, but the LSE that gains the same 500 MW of load in May would face an increased LCR that varies by month. This could lead to a shortfall in meeting the total LCR requirement. We note that Constellation et al. state that additional work on the proposal is needed, and Sempra Global acknowledges that the SES proposal would benefit from further discussion.
We remain open to consideration in future proceedings of a mechanism to true-up local procurement obligations to account for load migration, whether such mechanism is applied on a monthly, quarterly, or seasonal basis. We nevertheless conclude that there is no viable proposal for such a mechanism that can be adopted by the Commission at this time. In particular, we do not find that the SES proposal can be provisionally approved by this decision while remaining questions are left to a post-decision workshop. Further consideration by the Commission of a complete proposal on which there has been opportunity for comment would be required.
4.5. Local Area Aggregation
D.06-06-064 established aggregation of certain local areas for the 2007 Local RAR. This approach had two components. First, the Commission determined that each LSE's allocation of Local RAR for each local area would be based on its share of load in the IOU distribution service area. It then 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. It did so to address concerns about supplier market power in those six areas.
During the February 21 Track 1 workshop, stakeholders reached consensus in favor of an Energy Division proposal that (1) continues to calculate Local RAR based on load share of IOU distribution service area, and (2) continues the aggregation of the six PG&E local areas for compliance year 2008. Workshop participants expressed the concern that there will be a need to reevaluate the aggregation in future years. The workshop did not address allocation issues related to the Big Creek/Ventura Area proposed in the CAISO's 2008 LCR study.
The comments confirm consensus on these Energy Division recommendations, and we adopt them as reasonable extensions of the current program. As we stated in D.06-06-064, we would prefer not to provide for aggregation because it might lead to over- or under-procurement in some areas. Moreover, the need for aggregation may be an indication that there has not been sufficient investment in transmission and/or generation. We note however, that the CAISO determined on the basis of last year's experience that aggregation of the six PG&E areas is again acceptable, subject to continued monitoring. We accept the consensus of the participants that this aggregation is reasonable for 2008. We expect to again consider this question when we address local RA for 2009, and we agree with Constellation et al. that it would be helpful for the CAISO to report on an annual basis whether local area aggregation has led to CAISO backstop procurement.
The comments also reveal near-consensus that aggregation of the two local areas in the SCE territory should not be approved. AReM, however, asks that these two areas be aggregated. Countering AReM's request, SCE notes that generation located in each of the two areas will not mitigate overloads on transmission elements that are driving the other area's local capacity needs. Aggregating the areas could result in inefficient generation mix and additional CAISO backstop procurement, SCE contends. The CAISO concurs that such backstop procurement might be necessary, noting that if aggregation of these areas were permitted, LSEs could satisfy virtually all the combined obligation through capacity located solely in the LA Basin Area. As TURN notes, aggregation of the PG&E areas is appropriate because a number of those areas are small and/or contain resources primarily under IOU control. In the SCE territory, the Big Creek/Ventura Area has a relatively large LCR of 3,658 MW and the available resources (which exceed the LCR by a significant amount) are not predominantly under IOU control.
Although AReM raises general concerns about market power that lead to its proposal for aggregation of the SCE territory load pockets, it does not show that existing market power mitigation provisions are inadequate to address these concerns. Nor does AReM address the concerns about reliability and backstop procurement raised by the CAISO, SCE, and TURN. We find insufficient justification for aggregation of the LA Basin and Big Creek/Ventura Areas, and therefore determine that such aggregation will not be approved.
4.6. Waivers of Procurement Obligations
With respect to certain local areas, the LCR study identifies deficiencies in qualifying capacity resources. In the 2007 study the CAISO determined there were such deficiencies in the Sierra, Stockton, Greater Fresno, and Kern local areas that totaled to 466 MW. In the 2008 study the CAISO again identified such resource deficiencies in the same areas that total to 693 MW.
Because it would not be "reasonable to require LSEs to procure capacity that, according to the LCR study, does not currently exist in an area," the Commission directed the Energy Division to calculate reduced LCRs for those areas. (D.06-06-064, pp. 21-22.) The Commission stated that it was authorizing this "blanket waiver" treatment of deficiencies for 2007 only.
In its pre-workshop proposal, the CAISO noted that several transmission projects have been identified that will reduce the LCRs in currently deficient local areas for 2008 and 2009. The CAISO stated that for the projects scheduled to be in service in 2008, the precise amount of LCR reduction is being assessed in the 2008 LCR study. The CAISO states that to the extent the deficiencies are not eliminated, a continuation of the existing waiver policy appears appropriate for the same reasons expressed in D.06-06-064.
We will again approve blanket waiver of the local procurement requirement in the resource-deficient areas identified by the CAISO. LSEs should only be responsible for procurement to the level of resources that exist in the area.
In addition to the blanket waiver discussed above, D.06-06-064 approved a waiver process whereby an LSE would be able to specifically request waiver of a local procurement obligation if certain conditions are met. An important component of the adopted process is a capacity price of $40 per kW-year which functions as a threshold that could lead to a waiver grant. Energy Division proposed continuing this process, and there was general consensus favoring this proposal. IEP, however, contends that the waiver trigger of $40 per kW-year is unreasonably low, and proposes that it be doubled to $80 per kW-year. IEP asserts that is a conservative estimate of the cost of new entry.
We find insufficient record basis for modifying the waiver process or the trigger price adopted in D.06-06-064. As SCE notes, the Phase 2 Scoping Memo did not provide clear notice that proposed modifications to the waiver trigger price would be considered in Track 1. While IEP contended in its January 26, 2007 Track 1 proposal that the current waiver trigger is artificially low, and at that time it suggested that the Commission should consider the market price of capacity, this issue was not adequately addressed in the workshops. IEP's proposal to double the waiver trigger based on the cost of new entry first appeared in its post-workshop comments. As AReM points out, the trigger price was not adopted with the intention of its being a price signal for new capacity investment; it was established to provide an objective criterion for initiation of a regulatory process. Finally, as PG&E observes, the waiver trigger should not be raised without careful consideration of potential market power concerns, yet such consideration is not enabled by the current record.
5 SCE characterizes this as a phase-in of the Big Creek/Ventura area. As we understand SCE's phase-in proposal, Commission-jurisdictional LSEs would be placed on notice by the issuance of the Track 1 decision that the Commission has approved the establishment of the Big Creek/Ventura Area for purposes of the RA program beginning in 2009.
6 Aglet proposes that the SCE and SDG&E be directed to perform value of service studies similar in scope to the PG&E study. We find this proposal, which first appeared in Aglet's April 6, 2007 comments, to lack adequate substantiation. It may be appropriate to incorporate value of service analyses either in future LCR studies or in future Commission proceedings that consider the use of LCR studies if it can be shown that the benefit of this approach outweighs the cost to the IOUs of performing the requisite studies.
7 Pub. Util. Code § 345 provides that the CAISO "shall ensure efficient use and reliable operation of the transmission grid consistent with achievement of planning and operating reserve criteria no less stringent than those established by the Western Electric Coordinating Council [(WECC)] and the North American Electric Reliability Council [(NERC)]. See D.06-06-064, pp. 16-17, for a discussion of reliability options identified in the LCR report and their relationship to planning standards established by the NERC.
8 See Section 5 of this decision.
9 Although CMUA's members are not subject to the Commission's RA program, CMUA is concerned that decisions made in this proceeding will impact all entities within the CAISO Control Area. This is because the LCR study results serve as the foundation for determining Local Area Capacity obligations and the CAISO's backstop procurement.
10 PG&E Comments, pp. 6-7; TURN Reply Comments, p. 3. PG&E suggests that CAISO publish a study plan at the beginning of each year for stakeholder comment, that LCR stakeholders have adequate time to review and comment on draft LCR studies, that the CAISO meet with PTO stakeholders to review and verify draft results, that broader stakeholder meetings follow those PTO meetings and that the CAISO issue the final study after responding to questions and comments on the draft report. TURN proposes schedule reforms that would better allow stakeholders to review and comment on the study.
11 In proposals filed on January 26, 2007, AReM, Constellation et al., and CLECA/CMTA supported monthly true-ups. PG&E recommended exploration of seasonal or quarterly determinations that would include the opportunity for monthly trading. DRA proposed monthly compliance filings for the four summer months. SCE and SDG&E opposed monthly true-ups.
