4. RA Program Modifications

4.1. Standard Capacity Product

The Standard Capacity Product (SCP) is an attempt to reduce transactions costs associated with buying, selling, and trading capacity to meet RA requirements. In order to meet this goal, the SCP seeks to standardize the obligations of RA providers and other related terms of RA contracts. As implemented to date, the SCP places contract terms relating to availability standards and penalties in Section 40.9 of the CAISO Tariff.

The Federal Energy Regulatory Commission (FERC) approved the existing SCP on June 28, 2009. In that order, FERC directed the CAISO to work toward extending the SCP to currently exempt resources. At this time, certain resources whose Qualifying Capacities (QC) are determined based on historical data (including Qualifying Facility (QF) resources) and demand response resources are exempt from the SCP.

At the prehearing conference (PHC), some parties argued that ongoing activities in other proceedings would make it difficult to address issues relating to these resources in this proceeding. Further, PG&E pointed out that modifying counting rules for resources which are not part of the SCP would likely be contentious. Other parties argued that a methodology for counting these resources as part of the local procurement obligations could and should be developed in Phase 1 of this proceeding. For example, CAISO suggested that FERC issued an order directing CAISO to end the temporary exemption for demand response resources and various intermittent resources (wind, solar, non-dispatchable cogeneration, non-dispatchable biomass and non-dispatchable geothermal facilities) and this needs to occur for 2011 to be in compliance with the FERC directive.

In order for the SCP to be fully functional, it must be available as a commercially-viable product that LSEs can purchase and trade easily. Parties believe what is necessary is to find a way to end the LSE-based scheduled outage replacement obligation (sometimes referred to as a "replacement reserve" or "planned outage" issue).

Proposals and comments on this topic necessarily interweave our process in this rulemaking and the CAISO's ongoing stakeholder proceeding, which is discussing many of the same issues from the perspective of the jurisdiction of FERC and the CAISO.

4.1.1. Continue the Exemption for Demand Response

Demand Response (DR) resources are currently exempt from the SCP as adopted by FERC on June 28, 2009. CAISO and SCE argue that DR resources should continue to be exempt from the SCP at this time because there is no viable alternative proposal in the record. While we agree in theory with NAPP and EnerNOC that SCP ultimately should be extended to DR resources, there is no viable proposal to effectuate this change at this time. Indeed, CAISO has not included any proposal to include DR resources in the SCP in the recent draft proposals in the SCP II stakeholder proceeding. We note our support for the extension of SCP to DR resources and encourage the CAISO and other parties to work toward this goal, but we do not have sufficient information to take any further action on this issue at this time.

4.1.2. No Change to Replacement Obligation

At the PHC, many parties suggested that the LSE-based replacement obligation for RA capacity⁹ on scheduled outage impedes the viability of the SCP as a commercially viable product. In this proceeding,
two methods for ending the current LSE-based replacement obligation were discussed:

· Include "delivery requirements and penalties and replacement obligations in the [CAISO] tariff" so that "the CAISO then becomes responsible for enforcing delivery rather than each individual LSE, i.e., the CAISO assesses penalties and procures replacement capacity in the event that a supplier is unable to deliver RA capacity that has been sold and pledged for RA compliance."¹⁰ We refer to this approach as "tariff-based replacement."

· "[A]dd a Planned Outage Adder (POA) to each LSE's RA Requirement. The POA would account for planned outages that the [CAISO] has historically approved at-the-time-of the monthly supply plan submittal."¹¹

Calpine notes that the tariff-based replacement approach has been discussed in RA proceedings for several years.¹² This approach was explored in CAISO's SCP II stakeholder process with strong initial support from stakeholders.¹³ For example, AReM "strongly supports the removal of the current LSE obligation to replace RA capacity for units on scheduled outages" and suggests that, "ESPs do not control the RA units or have any knowledge about when outages may be scheduled. The most logical approach, therefore, is to transfer this obligation to the RA seller and incorporate the obligation into the CAISO's tariff."¹⁴ However, no consensus has been reached around the details of how this approach should be implemented. At the time of comments in this proceeding, many parties noted that they could not support the tariff-based replacement approach as it was being discussed at the time in CAISO's SCP II stakeholder process.¹⁵ SCE, for example argues that the proposal at that time would lead to increased costs due to CAISO procuring replacement capacity for all outages and therefore "effectively result in the procurement of capacity above what the CAISO currently relies on."¹⁶ CAC suggests that we should, "either maintain the current [LSE] scheduled outage replacement obligation or exempt Combined Heat and Power (CHP) resources from any rule that moves the obligation to suppliers."¹⁷ Finally, the tariff-based replacement approach has been removed from the scope of CAISO's SCP II stakeholder process.¹⁸

Although many parties suggest that SCE's POA approach holds promise¹⁹ some raised concerns. For instance, Calpine claims "[t]wo potential areas of concern are the monthly shaping of the procurement obligation and cross-subsidies from suppliers who require relatively few planned outages to those who require more extensive planned outages."²⁰ Dynegy's concern is that RA sellers must be able to take planned outages.²¹ SDG&E notes that it "is not inclined to support" the POA approach.²²

Parties noted that the POA approach is a modification to the overall RA structure. AReM "requests that the Commission defer consideration of any alternative proposals for modifying the structure of the RA program to a separate proceeding that integrates RA with the Planning Reserve Margin (PRM) proceeding and record."²³ WPTF suggests that the "most efficient solution to the scheduled outage issue is simply to base the system reserve margin on the annual peak."²⁴

In conclusion, we have no viable CAISO tariff-based replacement approach before us and the POA approach is not fully developed. Numerous parties suggest that it is premature for us to act on this issue.²⁵ TURN suggests that we "pursue an expedited process to resolve this single issue via a "Phase One B" decision in July or August of this year at the latest."²⁶ We decline to modify the existing LSE-based replacement obligation at this time. While we appreciate TURN's suggestion of a "Phase One B" to resolve this issue, we believe that the complex issues related to scheduled outage replacement are not well suited to an expedited process. We encourage CAISO and other parties to continue exploring the tariff-based approach in CAISO's stakeholder processes. Finally, we note that SDG&E argues that, "replacement capacity should be mandated only when the system would fall below 115% of the expected monthly load during the scheduled outage."²⁷ We encourage CAISO and other parties to explore this approach in future efforts to remove the LSE-based replacement obligation.

4.2. Qualifying Capacity

On December 18, 2009 the Energy Division published a report on "Qualifying Capacity Calculation Methodologies" (QC Report). The QC Report seeks to describe all currently applicable CPUC methodologies relevant to calculating the qualifying capacity (QC) of RA resources, some which were adopted in previous Commission decisions and others which have been implemented more informally. In addition to the current methodologies, the
QC Report includes a number of staff proposals for changes; in this proceeding parties have made further proposals to modify the calculation methodologies. Parties have commented extensively on the QC Report and the staff and party proposals.

We adopt a QC Methodology Manual as discussed below and as attached to this decision (Appendix B).²⁸ The QC Methodology Manual incorporates methodologies previously adopted both formally and informally in the past, and new and revised methodologies discussed in the QC Report and in parties' comments on the QC Report. In future RA proceedings, parties wishing to make changes to the QC calculation methodologies should include proposed revised or added text of the QC Methodology Manual.

In this proceeding, some parties proposed reconsideration of the wind and solar QC methodology. This issue was discussed at length in R.08-01-025 and was decided in D.09-06-028; we decline to reconsider it here.

4.2.1. Resource Classification Proposals

Section 3 of the QC Report describes the process of classifying resources; the classification process is critical because it determines which of the
QC methodologies applies to each resource. Section 3.1 of the QC Report describes the Energy Division's proposal to allow resource owners and scheduling coordinators to propose changes to the classification of their resources, with appropriate justification.

CAC makes several proposals relevant to the classification and QC of CHP or cogeneration resources. We will address these proposals one at a time. However, before addressing the merits of the proposals, we note that staff, in the QC Report, refers to these resources as "cogeneration" resources. In the record of this proceeding, parties have usually used the term "CHP." We understand these terms to be synonymous; for consistency, we will use the term CHP in this decision and the relevant sections of the QC Report are updated accordingly.

CAC proposes to "automatically [deem] non-dispatchable any resource that signs a [Qualifying Facility (QF)] [Participating Generator Agreement (PGA)]." SCE responds that the language of a QF PGA does not "mandate that these resources be non-dispatchable, and would not limit a resource with a
QF PGA from entering into an agreement with an LSE for dispatchability." In response, CAC proposes that if a CHP resource sets operating limits in its
QF PGA that render the resource non-dispatchable, the resource should be deemed non-dispatchable for net qualifying net qualifying capacity (NQC) counting purposes.

Further, CAC proposes that the counting methodology should differentiate between firm, as-available and hybrid CHP generation. CAC contends that this characterization more accurately reflects the generators' operational characteristics. This proposal is widely opposed.²⁹ For example, Calpine contends "it provides no assurance that such [firm] resources would actually provide energy at levels consistent with their available capacities during peak periods."³⁰

We note that the classification methodology proposed by the Energy Division in Section 3.1 of the QC Report allows for case by case determination of the dispatchability classification of individual resources, including CHP. No party opposed the Energy Division's proposal on classification. The Energy Division's proposal allows the specific details of a resource's operational characteristics, both physical and contractual, to be considered in its classification. Further, the resource owner or scheduling coordinator is best able to make this determination. Moreover, especially in light of the fact that SCP availability standard already applies to dispatchable resources, we believe the resource owner and scheduling coordinator have proper incentives to classify the resource appropriately. Therefore, we do not adopt the CAC classification proposals; instead, we adopt the staff proposal as part of the QC Methodology Manual.

4.2.2. Counting Rules for Non-Dispatchable Resources
(QC Report - Section 10)

Section 10 of the QC Report describes the methodology for calculating the QC of non-dispatchable resources that are not explicitly described in other sections. In Sections 10.1-10.3, the Energy Division proposes two changes: a methodology for new non-dispatchable resources (a topic that this Commission has not previously addressed) and a modification to the measurement hours, consistent with our D.09-06-028 for wind and solar resources. While no party directly opposed either of these proposals, CAC did propose some variations.

CAC proposes to calculate NQC on a monthly basis as opposed to a summer-months average for the entire year. In response, PG&E suggests that this approach should be applied to all non-dispatchable resources. SCE suggests that, if the Commission adopts CAC's proposal, it should also clarify that dispatchable thermal units are also able to receive monthly QC values.

A number of other resource types (e.g. wind, solar, and demand response) already have monthly QC values. The approach proposed by CAC to use monthly QC values for CHP is consistent with other previously adopted methodologies. The CAC proposal and both SCE and PG&E's suggested modifications are reasonable. Many dispatchable thermal units already do modify their NQC periodically during an RA compliance year and are thus able to take advantage of seasonal changes in available capacity. We adopt the proposal to calculate a monthly QC for all non-dispatchable resources, as part of the QC Methodology Manual.

CAC proposes to use the new resource methodology proposed by Energy Division for expansions to CHP facilities. SCE opposes this, contending that it will be difficult for the Commission to verify increases in capacity based on expansions. CAC claims that the procuring LSE or the CAISO may be able to verify the increase in capacity under the terms of the LSE's power purchase agreement or the generator's QF PGA. CAC also proposes to calculate the QC of new resources based on "existing resources with similar operating characteristics."³¹ While we are sympathetic to CAC's objection that additions to the generating capacity of an existing CHP resource may not be realized by the existing counting rules and the Energy Division's proposal, the CAC's proposal is not sufficiently developed at this time. We share SCE's concern that we do not have the ability to verify resource additions or subtractions to CHP resources. Further, we do not have a methodology before us to determine which resources have "similar operating characteristics" within the non-dispatchable classification. Although we will not adopt CAC's proposal today, we note that we support the policy goal of accurately and promptly measuring the capacity of expansions to CHP resources. We hope that this issue will be resolved in the future and we encourage CAC to work with the CAISO and LSEs to develop a framework to inform us and our staff of resource changes so that additions and subtractions may promptly be reflected in QC values.

Aside from CAC's proposed revisions, no party opposes the Energy Division's proposal to measure the QC of new
non-dispatchable resources using an approximation based on existing non-dispatchable resources. This proposal provides a reasonable approach to address a gap in our previously adopted rules, and it is approved as part of the
QC Methodology Manual.

No party opposes the Energy Division's proposal to change the hours of measurement for non-dispatchable resources. This proposal is consistent with
D.09-06-028 and is adopted. The QC Methodology Manual incorporates the
two staff proposals and the CAC proposal to use monthly QC calculations.

4.2.3. No Change to the Counting of Distribution Resources

PG&E proposes that distribution level resources that are not otherwise being counted for RA should be counted and should follow the same counting rules as resources connected at the transmission level, except that the distribution level resources will be deemed deliverable by the Commission. SCE agrees with PG&E that there may be some resources that are not properly accounted for by current counting rules, but is concerned that the Commission is not in a position to determine the deliverability status of all distribution resources. The CAISO expresses concern with deeming these resources deliverable.³² TURN, in referring to the Energy Division's February 18 Workshop Report, states:

"TURN fully agrees with the Energy Division's suggestion that "all resources should either be counted [as a reduction] in the load forecast or as a resource, but it is important to avoid double counting." Indeed, this seems to reflect simple common sense. The problem may therefore be more of an implementation question than a policy issue, one that will require some coordination between the CEC's load forecasting process and the CPUC's counting rules for distributed resources."

We agree with TURN and SCE that the record of this proceeding does not identify a specific class of distribution level resources that may not be currently counted either as demand reductions or as supply. Indeed, Section 4 of the
QC Report describes the deliverability of distribution level resources, yet no party has clearly stated that that description is inaccurate. If a party does identify an error in the description in the QC Report or a class of resources that is currently neither treated as demand reduction nor as supply resource, we encourage that party to describe the concern to the Energy Division and to bring the issue to the attention of this Commission. Further, as PG&E and SCE note, the deliverability of resources less than 20 MW connected to the transmission system is being discussed in CAISO's stakeholder process on Small Generator Interconnection Procedure. SCE further contends it is likely that the IOUs will modify their distribution interconnection procedures consistent with the results of CAISO's reform efforts.

We encourage the CAISO and the IOUs to seek a means of assessing the deliverability of these resources so that they may be treated as RA suppliers. Finally, we note the following SDG&E recommendation:

"SDG&E therefore recommends that each utility include in their distribution-level interconnection studies an assessment of whether the interconnecting generators should be treated as fully deliverable for Resource Adequacy purposes. This determination would establish a rebuttable presumption that the subject resources interconnected to the distribution system on the non-customer side of the meter should be certified as RA resources. If the CAISO believes the utility's determination creates a reliability concern, it can conduct the appropriate deliverability analysis for the amount of generation capacity that reaches the transmission system and present the results to the Commission to rebut the presumption in favor of deliverability."

We will not adopt SDG&E's proposals at this time, but expect these ideas to be discussed in future workshops or comments in this proceeding.

4.2.4. Eliminate Forced Outages and Derates from Data to Calculate QC and Possibly Include Resources Using Historical Data in the SCP

As noted above, resources which rely on historical production data for the calculation of QC are currently exempt from the SCP. This exemption prevents a double RA-related penalty for the same outage: one penalty through a reduced QC and another financial penalty via the SCP availability standard. The CAISO proposes that in order to eliminate the problem of double counting forced outages and derates that the outage hours be eliminated from the data set used for QC calculation. This would allow us, as well as FERC, to extend the SCP to these currently exempt resources. Specifically, the CAISO proposes that the Commission:

" . . . modify its RA counting rules either to: (1) eliminate forced outage and de-rate hours from its calculation of the QC of RA resources, or (2) use proxy energy output values for those hours. The ISO believes that the second option could be implemented by adopting an approach similar to the methodology the CPUC has previously approved to account for scheduled outages in the QC calculation for these types of resources."³³

CAISO further notes that it intends to present its proposal to extend the SCP availability metric to these types of resources for consideration at the
ISO Board of Governors' meeting (which occurred on May 17-18, 2010), followed thereafter by a tariff filing at FERC to implement the proposal effective January 1, 2011.

Both parts of this proposal are controversial. CalWEA/CCC strongly opposes both the proposals to include these resources in SCP and to eliminate the historical outage/derate data. CalWEA/CCC first contend that, "FERC did not intend to direct CAISO to end exemption for intermittents."³⁴ They further claim that, "the success of the SCP initiative does not at all depend on whether intermittent renewables and CHP projects can be shoehorned into the SCP mold" because RA capacity from these resources is not attractive for trading.³⁵ Further, they argue that existing incentives, namely the energy payment structure of most RPS contracts make the availability incentive of the SCP needless and duplicative. In effect, they argue, a double penalty will still exist, even if the relevant outages are removed from the data for QC calculation. In summary:

"Given the disparate RA counting rules, it is simply not possible to fashion an equitable and workable standard availability incentive for all types of resources. Given the strong existing incentives for intermittent and CHP resources to maintain high availabilities, CalWEA and the CCC submit that it is not worthwhile to try to "destandardize" the SCP availability incentive simply so that it can be applied to these resources. As a result, it is reasonable to retain the exemption for these resources."³⁶

DRA shares this view arguing that imposing an availability metric on intermittent resources that receive only energy payments and no capacity payments does not make sense and that there will be no increase in the availability of these generation resources. Finally, CalWEA/CCC suggest that the Commission will be faced with requests from renewable and CHP generators in the Renewables Portfolio Standard (RPS) and QF dockets to revise the pro forma contracts applicable to these resources in order to remove the existing incentives that, they argue, would be duplicated by the SCP mechanism.

CAC similarly argues that the Commission should ensure that CHP generators are not penalized twice for the same forced outage. Therefore, CAC contends the SCP should not apply to exempt resources until the issue of double penalties is resolved. CAC believes we do not have sufficient information in this proceeding to make that determination and that we should defer the issue of including these resources in the SCP.

Dynegy, however, responds to the arguments that SCP incentives would be duplicative by stating: "If the energy-based power purchase agreements that the representatives of these intermittent resources assert provide sufficient availability incentives for these resources, it's not at all apparent why they do not also provide sufficient revenues that would obviate the need for these energy resources to fight for poorly-fitting capacity payments."³⁷

CalWEA/CCC contend that utility-owned intermittent and CHP generation may not have as strong of incentives as generation under contract to an LSE, and therefore we should evaluate whether to remove the SCP exemption for such utility-owned projects. However, CalWEA/CCC do note that many of the existing wind and solar resources operate under grandfathered QF contracts and thus will not be subject to the SCP until those contracts expire. Further, they state that "[o]nly a fraction of the existing intermittent and CHP generation is under the CAISO's outage reporting system; the remainder is existing QF generation that is grandfathered out of these reporting requirements."³⁸ CalWEA/CCC claims that many currently exempt resources will be grandfathered from the SCP for the term of their current contracts, thus allowing time for the parties to those contracts to work out appropriate frameworks for incorporating the SCP availability standard.

Consistent with the CAISO tariff, and simple fairness of avoiding a double penalty, we find that eliminating the historical outage and derate data from the data set used to calculate the QC of these resources is an important pre-condition to including these resources in the SCP. The argument posed by CalWEA/CCC that other terms of certain resources contracts may duplicate the SCP penalties is not relevant to this finding. The elimination of the outage and derate data results in only a single RA-related penalty. It would be inappropriate for us to attempt to eliminate all potential duplication of incentives between our rules and bilateral contracts. Within the decision of whether or not to eliminate outage and derate hours, an important sub-decision is what hours should be eliminated. It is fair that exactly the same types of hours should be eliminated from the data set as are subject to penalties under SCP.

Section 40.9.4.2 of the CAISO Tariff states that, "Forced Outages, non-ambient de-rates, or temperature-related ambient de-rates" are considered for the availability calculation. Therefore we will eliminate these hours from the data set used for calculation of QC. Further, we find that it is appropriate to extend the methodology of replacing these hours with proxy data, in the same manner we adopted for scheduled outages in D.09-06-028 and as proposed by CAISO and the IOUs in this proceeding.³⁹ The QC Methodology Manual in Appendix B details this methodology.

Further, we expect that the SCP ultimately will be extended to include resources that use historical data as the basis of their QC (e.g., wind, solar, combined heat/power). We have noted in many previous decisions our support for an inclusive SCP.⁴⁰ However, no finalized, FERC-approved SCP for these resources exists at the time of closing the record in this phase of this proceeding. Therefore, we will adopt a similar strategy to last year's D.09-06-028, which accepted the SCP for RA compliance, but did not mandate it. If FERC does approve an SCP tariff for resources which use historical data as the basis for their QC later in 2010, the assigned ALJ may take comment in this proceeding to consider an appropriate response.

4.2.5. Demand Response

In D.09-06-028, the Commission directed the Energy Division to use the load-impact protocols to the greatest extent possible in developing the qualifying capacity of demand response resources. Since that decision, the Energy Division has developed a document describing the use of load-impact protocols in resource adequacy. This document was included in the QC Report.

The Scoping Memo allowed this issue to be included in the scope of
Phase 1 of this proceeding in order to allow comment on the Energy Division's document, with the potential that the Commission would resolve any disputes.

4.2.5.1. Counting Proxy Demand Resource and
Supply-Side DR

In this proceeding, EnerNOC suggests that QC of "supply-side demand response" should be determined using registered capacity that has been tested. In justification of this proposal, EnerNOC submits that Load Impact Protocols (LIPs) "are not an appropriate basis either for calculating RA capacity or for determining capacity payments for supply-side resources. Load impact protocols are complicated, non-transparent, and expensive to run."⁴¹ Further, EnerNOC argues, referring to the LIPs, that "A simpler means of determining RA capacity for DR resources participating in the wholesale market would be to take the capacity registered by the [Proxy Demand Resource (PDR)], subject it to a test, and determine the tested capacity as RA-eligible."⁴² EnerNOC describes its proposal this way:

"If California is going to treat demand resources comparably to generation resources, the demand response provider, representing the resource, should be able to register the capacity associated with the resource that is participating through the CAISO. The determination of whether or not the registered capacity is capable of performing at that level will be based upon the actual performance of the resource or, if not called within a commitment period, testing. If the resource does not perform to the capacity level specified, the resource will face penalties."⁴³

This proposal provoked considerable controversy. TURN, AReM, and NAPP support the EnerNOC proposal.⁴⁴ AReM agrees with EnerNOC that the current approach using load-impact protocols is complex, non-transparent and unduly time-consuming. TURN adds that "If a DR program is willing and able to operate like a supply-side resource, TURN sees no reason why the same capacity test that applies on the supply side could not be used to determine the QC for these programs."⁴⁵

CLECA, Dynegy, PG&E, SCE, and DRA oppose EnerNOC's proposal.⁴⁶ Generally, these parties are concerned about consistency with the load impact protocol (LIP) measurement of other DR programs and the accuracy of EnerNOC's proposal. Dynegy summarizes the issue: "If the Load Impact Protocols are adequate for determining the RA value of IOU demand response programs, EnerNOC has not satisfactorily demonstrated why they are inadequate for determining the RA value for non-IOU demand response programs."⁴⁷

Several parties⁴⁸ have characterized the distinction between DR that would use the LIPs and DR that would use a contract capacity as a distinction between IOU operated DR and non-IOU operated DR. We will not make this distinction between IOU and non-IOU DR. Instead, the counting rules for all resources should be operator-neutral, and should only differentiate between resources based on the operational characteristics of the resources. We recognize that in some cases, especially with DR, operational characteristics may be substantially correlated with the characteristics of the resource operator, but we decline to differentiate based on the identity of the operator.

SCE contends that EnerNOC's proposed methodology is overly simplistic and unreliable because it cannot control for variations in conditions at the time of different DR events. Further, SCE suggests that this approach may result in artificially inflating QC values for DR resources.

In response to SCE's concerns, EnerNOC explains that it uses a portfolio of different customers: "This process of portfolio development allows EnerNOC to register a DR resource that is highly reliable and will perform at a predictable level irrespective of conditions at the time of the event."⁴⁹ Further, EnerNOC notes that an underperforming Proxy Demand Response resource "will be charged the uninstructed deviation for any real-time shortfall in its performance relative to day-ahead bids and potentially sanctions for failure to provide the resource up to the committed level," and that "consistent underperformance will result in . . . QC being appropriately adjusted downward."⁵⁰

From a policy perspective, we agree with TURN and EnerNOC that with proper economic incentives for accuracy, it is reasonable that DR resources that act like a dispatchable supply resource may appropriately have QC evaluated via a test, similar to dispatchable conventional generators. We note that parties such as CLECA have expressed concerns with the accuracy of the baseline methodologies used to measure performance of DR resources for settlement purposes; in making this policy determination, we do not need to address the accuracy of the baseline methodologies at this time. It is likely that a DR program that is subject to the RA Must-Offer Obligation to bid into the CAISO energy markets is subject to uninstructed deviation penalties for real-time performance problems, and is subject to SCP availability penalties, will have adequate incentives to set a realistic QC for itself and that the CAISO will be able to verify this by a test. However, no party has demonstrated that any DR resource or class of DR resource before us today meets this description.

In conclusion, we reiterate our policy view that dispatchable DR resources with financial incentives for availability and performance comparable to those of dispatchable supply resources should be able to receive QC with a comparable testing methodology. However, unless and until it is demonstrated to us, in this or a future RA proceeding, that such a DR resource exists, we will retain our current policy that the LIPs are used to establish the QC of DR resources to the maximum extent possible.

4.2.5.2. Grossing-Up DR for Avoided Line Losses

PG&E and SCE propose to "gross-up" the QC of dispatchable DR resources for avoided line losses. The QC report states that DR suppliers may submit LIP data with and without including avoided line losses, but that LIP data without line losses shall be used. PG&E and SCE argue that the load forecasts used to determine RA requirements include line losses and that DR resources avoid line losses by reducing the need to transmit power over the transmission and distribution (T&D) networks. Therefore, DR resources should receive the benefit of avoiding these losses. DRA, SDG&E, and TURN all support this proposal.⁵¹ SCE proposes⁵² the following equation to implement this proposal:

DR RA Value = 1.15 * DR Load Impact * (1.00/(1.00 - T&D Line Loss Rate)) where, T&D Line Loss Rate = 3% + IOU-specific Distribution Loss Factors.

SCE further cites D.06-07-031, which adopted a 3% transmission loss factor and D.05-10-042 which adopted utility specific distribution loss factors. Objecting to this proposal, CAISO asserts that, "the fundamental assumption underlying the proposals is that demand response will in all locations and all circumstances reduce line losses but that the rest of the RA resources will not."⁵³ In response, SCE claims DR avoids line losses because the resource is supplied at the customer meter level, and, therefore, eliminates the need to account for T&D line losses. TURN would support the use of a "gross up" for losses, unless and until it is shown that in the specific situations, line losses are not in fact avoided by the operation of DR.

We agree with TURN and SCE and find that losses are included in the load forecast used for RA requirements and that DR resources provide a means of balancing supply and demand without accruing line losses. SCE's proposal is a reasonable means of accounting for the line losses avoided by DR. Therefore, we adopt the proposal to gross up dispatchable DR for avoided line losses, including the formula proposed by SCE.

4.2.5.3. Continued Full Year Local RA Credit for Air Conditioner Cycling (AC Cycling) Programs

The CAISO proposes that the Commission "modify the load impact protocols discussed in Section 11 of the QC Report so that they count demand response resources enrolled in air conditioning cycling programs as local RA capacity only in the summer months when the resources are actually available and capable of performing."⁵⁴ The CAISO's primary concerns with the counting rule are based on the fact that, at the current level of participation in demand response air conditioning cycling programs, this approach allows approximately 900 MW per month of "phantom" demand response to be counted as local RA capacity during each of the non-summer months.⁵⁵

Dynegy⁵⁶ supports the proposal to only count AC Cycling programs during the summer months, but several other parties⁵⁷ oppose the proposal. Parties opposed to the CAISO proposal suggested that the status quo is consistent with many other aspects of the current RA program. TURN⁵⁸ summarizes:

"While the AC cycling programs may not be available during the winter, the associated AC load also is not there in the off-peak months, which should translate into a lower local RA requirement. But the CAISO does not believe that it is practical to develop monthly or seasonal local RA obligations, because of the extensive amount of work that would entail. TURN submits that it makes little sense to require LSEs to acquire replacement local RA capacity in the off-peak months because of the absence of AC cycling when we don't even know what the real need for local RA capacity really is in those same off-peak months."

The entire structure of the local RA program uses summer peak values for not only load forecasts, but all supply resources. We believe that this conservative approach provides a significant margin of safety in the off-peak months. Therefore, we will continue the current treatment of AC Cycling programs, which is consistent with the larger local RA program.

4.2.5.4. Changes to Measurement Hours will be
Effective in 2012

In Section 11.1 of the QC Report, Energy Division proposes that, for consistency with other QC counting rules, DR programs should be measured over the same hours as other resources.⁵⁹ DRA supports the Energy Division's proposal.⁶⁰ Staff noted⁶¹ that the measurement hours proposed do not align with the hours of operation of some current DR program designs and asked for feedback from the IOUs about when the program designs could be changed accordingly. PG&E suggested that, "Consideration of any potential change in the time period used to evaluate the RA value of the DR programs by the Commission should be aligned with consideration of design changes
(i.e., operating hours) to future DR programs."⁶² SDG&E suggests:

"For ease of administration, however, SDG&E urges the Commission to refrain from implementing the proposed change in hours until the 2012 RA compliance year. As noted in the January workshop, the proposed hours do not align with most current IOU demand response program designs. The currently approved IOU demand response program cycle runs from 2009 through 2011. Beginning in early 2011, IOUs will begin filing applications for the 2012 - 2014 demand response program cycle. SDG&E believes that the proposed change in hours could be incorporated into the 2012 - 2014 applications, and if approved, implemented in the 2012 programs."⁶³

TURN makes the same suggestion and adds that:

"TURN believes that this Commission should endorse the principal of employing the revised hours at this time, so that everyone will be on notice that program changes may need to be considered in the next round of DR program applications. Since those applications are likely to be filed in early 2011, this year's RA decision would the appropriate place to establish such policy guidance, so that it can be taken into account in the upcoming utility applications."⁶⁴

SCE, however, opposes the change in measurement hours,⁶⁵ citing
D.09-08-028, which adopted specific hours of operation (2 p.m. to 6 p.m.) for SCE's Critical Peak Pricing program.⁶⁶ SCE contends that this General Rate Case decision operates on a different three year cycle from the three-year program cycle for DR described in SDG&E's comment above. Therefore, SCE claims it may not be possible to modify the Critical Peak Pricing program for 2012.

We wish to avoid unintentionally under-valuing DR programs which cannot immediately adapt to new measurement hours. Accordingly, we largely agree with the TURN and SDG&E analysis of this issue and believe that DR program designs implemented for the 2012-2014 DR program cycle should be able to incorporate the proposed change in measurement hours. However, we acknowledge that some DR program designs may not be able to incorporate this change. Therefore, we adopt the staff proposal with the following modifications:

· The proposed change in measurement hours will be implemented for compliance year 2012, but not 2011. Beginning in 2012, the measurement hours shall be the hours shown in Table 2 of the QC Report:

Jan-Mar, Nov and Dec:	HE17 - HE2167 (4:00 p.m. - 9:00 p.m.)
Apr-Oct:	HE14 - HE18 (1:00 p.m. - 6:00 p.m.)

· To ease the transition to the new measurement hours,
DR program operators may request that specific DR programs continue to be measured using the existing hours (2 p.m. to
6 p.m.) during 2012, or potentially future years, if they have a fixed operational period set by a Commission decision. In order for DR program operators to request use of the 2 p.m. to 6 p.m. measurement hours, the operator shall file a proposal to do so in Phase 2 of this proceeding that identifies, at a minimum, the specific program(s), it's (their) operational period(s), a specific citation from a Commission decision setting this operational period, and when the operational period may be changed. To be clear, we anticipate that most or all DR programs that will be evaluated in the 2012-2014 DR program applications will not use this process. Only those programs whose operational periods cannot be changed in those applications or another venue in time for 2012 implementation (for instance due to previously adopted rate design) should use this process.

Finally, we note SDG&E's proposal to use a 1-in-10 year forecast in calculating a DR resource's QC with the LIPs. However, we view this as a separate issue from the measurement hours in the staff proposal discussed above. This load forecast issue has not been fully vetted in this proceeding and we will not discuss it or adopt it here. If SDG&E or other parties believe this proposed change in the load forecast has merit, they should file a proposal to do so in Phase 2 or a later RA proceeding.

4.3. Implementation Proposals

4.3.1. Resource Adequacy Penalties

Public Utilities Code Section 380 requires the Commission to establish and enforce a resource adequacy program. Past decisions and resolutions establish three primary penalties for different types of RA procurement deficiencies. However, these penalties do not differentiate between deficiencies which are or are not remedied in a timely manner.

The current RA program utilizes the citation program was adopted in Resolution E-4195 and provides that LSEs may be fined specified amounts for failure to make timely filings in the manner required, and for small procurement deficiencies. In addition D.05-10-042 and D.06-06-064 establish penalties for System and Local RA procurement deficiencies. The penalty structure is provided in the table below:

	Small Procurement Deficiency	System Procurement Deficiency	Local Procurement Deficiency
Replaced within five business days of the date of notification	$1,500/incident	$9.99/kW-month	$3.33/kW-month

D.06-07-031 stated that: "RAR violations will be handled first through action by the Energy Division such as a notification letter providing the LSE with a limited time to resolve the violation, and then, if the LSE fails to do so, the Energy Division would recommend that the Commission initiate an enforcement proceeding." (Finding of Fact 7.)

Additionally, D.06-06-064⁶⁸ states that LSEs that fail to meet their local RA procurement obligation are subject to a penalty equal to 100% of the cost of new capacity, which is currently determined to be $40/kW-year. D.06-06-064⁶⁹ further stipulates, in context of local RA filings, that, "the penalty for failure to make a timely filing should, after a grace period not to exceed 10 calendar days, be equal to the penalty for a deficiency." Finally, D.05-10-042⁷⁰ states that LSEs that fail to meet their System RA procurement obligation are subject to a penalty equal to 300% of the monthly cost of new capacity.

The Energy Division's staff proposed to modify the current RA penalty structure to provide LSEs with an incentive to promptly cure any RA deficiencies:

	Small Procurement Deficiency	System Procurement Deficiency	Local Procurement Deficiency
Replaced within five business days of the date of notification	$1,500/incident	$3.33/kW-month	$5.00/kW-month
Replaced after five business days of the date of notification	$3,000/incident	$6.66/kW-month	$9.99/kW-month

An alternative proposal was filed by AReM, PG&E, SCE, and SDG&E:

	Small Procurement Deficiency	System Procurement Deficiency	Local Procurement Deficiency
Replaced within 10 business days of the Date of notification	$1,500 first incident in calendar year; $3,000 for each incident thereafter in a calendar year	$5.00/kW-month	$1.70/kW-month
Replaced after 10 business days from the date of notification or not Replaced	LSE pays the applicable System or local RA penalty for the deficiency	$9.99/kW-month	$3.33/kW-month

Proponents contend that their alternate proposal addresses the Energy Division's needs to add an incentive for LSEs to cure RA deficiencies in a timely manner and also establishing hard deadlines to the penalty rules. SCE claims the alternative proposal is similar to the Energy Division's proposal in that it establishes an incentive to cure promptly a deficiency through the reduction in the penalty amount, with the major difference being that the parties' alternative proposal maintains the current penalty amounts."⁷¹

Finally, joint parties request to change the RA waiver process.

The waiver process established in D.06-06-064 requires LSEs to request the waiver at the time they make their local RA showing. "The waiver request must include both of the following:

(1) a demonstration that the LSE reasonably and in good faith solicited bids for its RAR capacity needs along with accompanying information about the terms and conditions of the Request for Offer or other form of solicitation; and

(2) a demonstration that despite having actively pursued all commercially reasonable efforts to acquire the resources needed to meet the LSE's local procurement obligation, it either:

(a) received no bids; or

(b) received no bids for an unbundled RA capacity contract of under $40 per kW-year or for a bundled capacity and energy product of under $73 per kW-year; or

(c) received bids below these thresholds but such bids included what the LSE believes are unreasonable terms and/or conditions, in which case the waiver request must demonstrate why such an LSE's waiver request that meets these requirements is a necessary but not a sufficient condition for the grant of such waiver. The Commission will also consider other information brought to its attention regarding the reasonableness of the waiver request"⁷²

The alternative RA penalty proposal requests that this waiver process change to the following:

"LSE's may request a waiver up to 10 days prior to the year-ahead local RA compliance filing or the True-up Filing for local RA, as applicable. The Energy Division must rule on the request on or before the date the applicable Local RA filing is due. If the Energy Division rejects the waiver request, the LSE will have 15 days from the date of notification of the rejection to procure additional capacity, no penalty will apply unless the LSE fails to cure the deficiency within the 15 days of notification of rejection. The Commission should state in a decision that, barring an overriding demonstrable circumstance, satisfaction of the requirements in
D.06-06-064 is a sufficient condition to grant a waiver request."⁷³

TURN supports the alternative proposal penalty levels.

Dynegy, J.P. Morgan and Calpine support the Energy Division staffs proposal to triple the local RA deficiency penalty. These parties feel that penalties for RA deficiencies should reflect the greater importance of local resources for grid reliability. Calpine contends that "penalties should be related to the potential harm caused by deficiencies."⁷⁴ In addition, Calpine does not support conditions on the blanket waiver approval. Dynegy supports the Energy Division's proposal that modifies the RA penalty structure to increase the penalty for a local deficiency, but does not support reducing the penalty amount for a deficiency in system RA capacity.

DRA argues that there is no need to modify the current RA procurement penalties. DRA claims that most of the deficiencies in procurement are related to the local RA that is due to shortage of local supply issues, so that increasing the level of penalties will not solve this problem.

SDG&E supports the alternative RA penalty proposal. PG&E recommends the Commission adopt the alternative proposal because it provides additional leeway for correcting deficiencies and moderates the penalty levels.

4.3.2. Discussion

We will adopt a new RA penalty structure which combines parts of the Energy Division's proposal and the alternative structure proposed by certain parties, as shown below. We also eliminate the provision stated in D.06-07-031 that would provide an LSE with a limited period of time to resolve a violation after being notified by Energy Division. The new penalty structure will be in effect for violations which occur after the date of this decision.

	Small Procurement Deficiency	System Procurement Deficiency	Local Procurement Deficiency
Replaced within five business days of the date of notification	$1,500 first incident in calendar year; $3,000 for each incident thereafter in a calendar year	$3.33/kW-month	$3.33/kW-month
Replaced after five business days from the date of notification or not replaced	LSE pays the applicable System or Local RA penalty for the deficiency	$6.66/kW-month	$3.33/kW-month

A problem with the existing penalty structure is that it provides no guidance as to what happens if the LSE does not replace capacity within the specified number of business days after notification. While it is important for capacity to be replaced quickly, the LSE may choose not to do so. For example, an LSE may find it to be less expensive to pay the penalty than to fix the procurement deficiency. Therefore, it is appropriate to both provide an incentive for timely replacement and to provide a clear penalty if this does not occur.

The adopted penalty levels provide this clear incentive for system RA and small procurement deficiencies. However, in comments on the proposed decision, parties argued persuasively that a local RA penalty level that exceeds the local RA waiver trigger price ($40/kW-yr) may, in circumstances of market power, effectively raise market prices for local RA. While it is our intent that the waiver process should provide sufficient market power mitigation to negate this concern, we are persuaded that the local RA penalty price should not exceed the waiver trigger price at this time.

We adopt the Energy Division's proposal to eliminate the 10-day grace period or opportunity to cure defective filings after notification of a possible violation that was adopted in D.06-06-064.⁷⁵ The RA program was set up to ensure that LSE had enough resources procured to meet the forecasted demand that they supply. The program requires an annual Year-Ahead filing where LSEs are to show 90% of their system requirements for the upcoming compliance year. Additionally LSEs are required to make monthly Month-Ahead showings that show they meet 100% of their RA requirements for the coming compliance month. After filing their showing for the month ahead, the Energy Division staff checks their showing for compliance and the CAISO validates their resource showing using the supply plans submitted by the generators. This process can take 1-2 weeks to complete. Once everything has been checked, correction notices are sent out to LSEs to correct their monthly showing within seven calendar days. This is followed by a second supply plan validation, if they have to show additional resources to their RA showing. The second set of supply plan validations could take up to another week. In order to implement this program efficiently and ensure that enough resources are procured for the month ahead,LSEs can not be given a 10-day grace period.

Additionally, we reject the alternative RA penalty proposal to change the local waiver process and requirements. Historically, the local waiver only has been applied for a total of two times. It has been approved one of those two times. The rejection of the other application was due to the LSE not meeting the established criteria. During this proceeding, the Energy Division published both the letter approving the waiver and the resolution denying the waiver on its website, as requested by parties. This was done to provide parties with more transparency and certainty around the waiver process. Given the historical background surrounding the local waiver, we feel there is no need to add any additional language to the rules surrounding its process.

Finally, we adopt the Energy Division's proposal to round RA deficiency penalties up on a monthly basis. Current practice is to round up on a monthly basis and we see no need to modify this at this time.

4.3.3. Load forecast timeline

In addition to the RA penalty proposal, the Energy Division at workshops proposed a timeline for changes to the load forecast. Staff notes that LSEs currently submit a month ahead forecast 60 days prior to the month they are forecasting. The monthly load forecast is submitted 30 days before the filing of the Month-Ahead RA showing. This monthly load forecast is used as part of the month-ahead compliance check because it may change the load forecast which in turn changes the RA obligation. In some cases, LSEs have filed updates to their load forecasts after they file their month-ahead RA showing. The Energy Division proposes that LSEs may, at the discretion of CEC staff, file changes to their load forecasts up to 25 days before the due date of the month-ahead compliance filings. Staff further notes that with the implementation of Senate Bill 695, load migration is anticipated to increase and this may lead to more requested changes in the load forecasts.

No party commented on this proposal. We see this proposal as reasonable as an administrative part of running the RA program. We adopt the Energy Division's Division timeline for changes to the load forecast.

4.3.4. RA Record Retention Policy

Currently there is no established timeline for the RA record retention process. With expected load migration due to re-opening of direct access, and the effect load migration has on the month-ahead RA showing, there needs to be an established timeline.

At workshops, the Energy Division proposed a RA records retention policy. Staff proposed that the Energy Division shall keep all RA filings and related materials for three calendar years after the end of the compliance year. Staff proposed to generally destroy records past their retention date, with discretion to retain records for statistical, enforcement or other purposes.

No party commented on this proposal. We see this proposal as reasonable as an administrative part of running the RA program. We adopt the Energy Division's RA records retention policy.

4.3.5. Local Area Substitution

D.06-06-064 at 42, established the requirement that LSE must show in their compliance filings all their local RA capacity in order to avoid unnecessary over-procurement.

In the CAISO's tariff for the SCP, RA resources must be "available" for a certain percentage of the peak hours in a certain month or they will be subject to unavailability charges. The availability of unit may be reduced by a forced outage but not by a scheduled outage. A provision of the tariff allows for LSEs to lessen the burden of financial impacts, due to forced outages, by substituting capacity from non-RA units. Additionally, the tariff includes an additional requirement that if the resource is a local resource, the substitute unit must have equivalent characteristics to the RA unit on being replaced.

According to SCE, under the CAISO's SCP, RA resources are required to be available for a certain number of hours, or be subject to unavailability charges. For some of these resources within local areas, the LSE or the generator would have the ability to substitute and avoid those unavailability charges. Current RA rules require LSEs to list all of their contracted local resources in their filings, thereby making it impossible to substitute for local resources. SCE would give generators or LSEs that are subject to the reporting requirement the ability to substitute resources in this situation.

SCE proposes that the Commission eliminate the requirement that LSEs be required to show all their local resources in their year-ahead LCR showing, provided that any local resources that are listed on an LSE's year-ahead LCR filing be required to be included, if available, in that same LSE's monthly system filing. SCE claims it is unable to utilize CAISO's substitution rule because none of its local resources, which are under contract, qualify as non-RA. SCE argues that by eliminating the requirement to show all local resources in the year-ahead filing, LSE's that already have an excess of local resources under contract will better be able to mitigate customer costs by eliminating unnecessary acquisition of additional local capacity, or avoiding the imposition of unavailability charges.

D.06-06-064 protects against unnecessary over-procurement. If an LSE that is long on its local RA is allowed to withhold the resources from the RA showing, then an LSE that is short on its local RA may have no access to the resources being held by the other LSE and may result in the CAISO assuming that additional local RA procurement is needed.

AReM proposes that in order to remedy SCE issue, the RA template can be changed to reflect an additional piece of information that marks the local resource as RA eligible.

The CAISO objected to SCE's proposal stating "To the extent that any procured RA resources are not included in the year-ahead showing, the ISO could be led to conclude that there is an individual and/or collective deficiency in meeting the local capacity requirements, which could result in ICPM procurement for a full year, with the cost allocated first to the individually short load serving entities and then the "collective deficiency."⁷⁶

SCE responded to the CAISO's concern by stating: "SCE is supportive of the Commission requiring LSEs to inform the CAISO of additional local resources under their control that they did not identify in their year-ahead local showing in the event the CAISO notifies market participants of local area capacity deficiency. If the CAISO accepts those resources to meet the local deficiency, those local resources would become (capital L) local RA resources and included in a supplemental LSE local RA filing."⁷⁷

We will adopt the following approach to address SCE's concern. We will end the requirement, stated in D.06-06-064, that LSEs list all local resources under their control on their local RA filing.  At the time of the year-ahead local filing, each LSE shall submit, in addition to its other year-ahead filings, a list of all local resources it controls  (via ownership or contact)  that are not  listed as RA resources and committed to the CAISO up to their full NQC in the year-ahead local filing. This "additional local resource list" shall be sent to the CPUC, CAISO, and CEC. CAISO will then proceed to conduct the collective residual local deficiency analysis considering only the resources shown on the local filings, and not those on the additional local resource list. Finally, after CAISO has published the local residual deficiencies, LSEs may commit resources from their additional local resource list as RA resources in order to meet residual collective local deficiencies identified by CAISO.  In the event that no residual collective local deficiencies, those units on the list will be considered non-RA capacity, not committed to the CAISO via supply plans.  Thus those units will be available for substituting under the SCP process. As adopted in D.06-06-064 and D.07-06-031, and as discussed in the annual RA Compliance Guide, there is a period after the due date of the year-ahead filing for this additional showing process (usually due on December first of each year). We direct Energy Division to publish revised RA guides and templates according with this process.

⁹ We adopted this rule in D.06-07-031; see p. 10 of that decision for details.

¹⁰ Calpine Proposals at 5-6.

¹¹ SCE March 5, 2010 Proposal at 1.

¹² SCE March 5, 2010 Proposal at 1.

¹³ SCE March 5, 2010 Proposal at 1.

¹⁴ SCE March 5, 2010 Proposal at 1.

¹⁵ SCE March 5, 2010 Proposal at 1.

¹⁶ SCE March 5, 2010 Proposal at 1.

¹⁷ SCE March 5, 2010 Proposal at 1.

¹⁸ CAISO Revised Draft Final Proposal at 7; http://www.caiso.com/2771/27717a905e6a0.pdf.

¹⁹ See: CalWEA/CCC Comments pg 11; WPTF Comments at 3-4; Calpine Comments
at 10; Dynegy Comments at 7; and Mirant Comments at 5-6.

²⁰ Calpine Comments at 10.

²¹ Dynegy Comments at 7.

²² SDG&E Comments at 7.

²³ AReM Reply Comments at 4.

²⁴ AReM Reply Comments at 4.

²⁵ DRA Comments at 2; CAISO Comments at. 2; CLECA Comments at 5; SDG&E Comments at 5; CAC Reply Comments at. 10; and PG&E comments at 10.

²⁶ TURN Reply Comments at 3.

²⁷ SDG&E Reply Comments at 1.

²⁸ For clarification, we use the term "QC Report" to refer to the Energy Division document used in workshops, while the "QC Methodology Manual" is what is adopted today.

²⁹ See: CAISO Comments at. 21, Calpine Comments at. 4-6, Dynegy Comments at 14, PG&E Comments at 4, and SCE Comments at 21-22.

³⁰ Calpine Comments at 6.

³¹ CAC proposals at 9.

³² CAISO Comments at 17-18.

³³ CAISO Proposals at 5.

³⁴ CalWEA/CCC Comments at 2-3.

³⁵ CalWEA/CCC Comments at 6.

³⁶ CalWEA/CCC Comments at 10.

³⁷ Dynegy Reply Comments at 5.

³⁸ CalWEA/CCC Comments at 7-8.

³⁹ PG&E Comments at 5; SCE Comments at 8; SDG&E Comments at 8.

⁴⁰ See, e.g. D.09-06-028 at 42; D.06-07-031 at 4; D.05-10-042 at 26; D.04-10-035 at 42.

⁴¹ EnerNOC Proposals at 7.

⁴² Ibid.

⁴³ EnerNOC Comments at 7-8.

⁴⁴ AReM Comments at 5-6; TURN Comments at 4; and NAPP Reply Comments at 4-5.

⁴⁵ TURN Comments at 4.

⁴⁶ CLECA Comments at 4; Dynegy Comments at 13; PG&E Comments at 4; SCE Comments at 23-26; and DRA Reply Comments at 9.

⁴⁷ Dynegy Comments at 13.

⁴⁸ SCE Reply Comments at 11.

⁴⁹ EnerNOC Reply Comments at 5.

⁵⁰ EnerNOC Reply Comments at 5-6.

⁵¹ DRA Comments at 3; TURN Comments at 3-4; SDG&E Comments at 9-10.

⁵² SCE Proposals at 9 and SCE Comments at 18.

⁵³ CAISO Comments at 19.

⁵⁴ CAISO Proposals at 10.

⁵⁵ CAISO Comments at 11.

⁵⁶ Dynegy Comments at 12.

⁵⁷ DRA Comments at 3, TURN Comments at 4-5, SDG&E Reply Comments at 7, PG&E Reply Comments at 1.

⁵⁸ TURN Comments at 4-5.

⁵⁹ QC Report at 25.

⁶⁰ DRA Comments at 3.

⁶¹ February 18, 2010 Workshop Summary at 5.

⁶² PG&E Comments at 2.

⁶³ SDG&E Comments at 12.

⁶⁴ TURN Comments at 3.

⁶⁵ SCE Comments at 27 and SCE Reply Comments at 12.

⁶⁶ D.09-08-028 at 26.

⁶⁷ HE indicates "hour ending," or the 60 minutes that end at the numbered hour, in
24-hour time. For example, HE17 indicates the 60 minutes beginning at 16:00
(i.e. 4:00 p.m.) and ending at 16:59.

⁶⁸ At Conclusions of Law 25 and 26.

⁶⁹ At 68-69.

⁷⁰ At 94 and Conclusion of Law 21.

⁷¹ SCE Comments on Phase 1 issues at 12.

⁷² D.06-06-064 at 72-73.

⁷³ Alternative Proposal to Modify Current RA Penalty Structure at 6.

⁷⁴ Calpine comments at 3.

⁷⁵ D.06-06-064 at 68-69.

⁷⁶ CAISO Comment on Phase 1 issues at 15.

⁷⁷ SCE comments on Phase 1 at 11.