Resource Adequacy Working Group Wiki

Aliso Canyon Reliability

Background

On October 23, 2015, a significant natural gas leak was detected at Southern California Gas Company’s (SCG’s) Aliso Canyon natural gas storage facility. After several unsuccessful attempts to plug the leak near the wellhead, the California Department of Conservation issued an order to SCG prohibiting the further injection of gas into the facility in December 2015, and Governor Brown issued an Emergency Proclamation in January 2016.

On February 12, 2016, SCG successfully stopped the leak, and the well has been permanently sealed and Aliso Canyon, which normally operates at its full capacity of 80 billion cubic feet (Bcf), is now capped at 15 Bcf of natural gas storage for the foreseeable future. Aliso Canyon is the sole gas supply resource for 18 fast-ramping natural gas generation facilities (9,800 MW in total) in the LA basin during summer peak periods. Removal of Aliso Canyon from service has created a great concern about reliability during summer 2016, when peak demand for natural gas reaches 3,211 Bcf (a massive 61% comes from electric generation facilities). With the legislature in recess, CESA is assessing its 2016 legislative prospects and considering adjustments to its strategies.

On May 10, 2016, SB 380 was approved, which prohibited the reinjection of gas into the facility until a comprehensive safety review was completed. 

2016-2019 Reliability Assessments & Plans

The Joint Agencies (CEC, CPUC, CAISO, ARB, LADWP) commenced and published studies on the impact of the Aliso Canyon gas leak on gas and electricity grid reliability. The message is clear that Southern California is likely to experience future curtailments of non-core customers, and in extreme situations, core customers could be at risk as well. 

On April 5, 2016, the Joint Agencies released a draft Action Plan to preserve reliability of electrical service this summer in the greater LA area, which includes the following near-term actions:

• Use of 15 Bcf of natural gas that was preserved in the Aliso Canyon facility for use during periods of peak demand

• Strong energy conservation programs, such as the “Flex Alert” campaign, to help local residents reduce their energy use during peak demand

• Greater coordination among state and local gas and electric utilities

• More energy efficiency programs

• Closer matching of gas supply and demand by large gas customers

In collaboration with LSA and SEIA, CESA brainstormed a short-list of energy storage options.

On April 8, 2016, a joint agency workshop was held on April 8 to discuss the near-term gas and electricity reliability risks to the LA Basin due to SCG’s Aliso Canyon gas storage facility leak, as well as the Joint Agencies’ draft Action Plan. At this workshop, CESA presented its ideas on near-term energy storage solutions to Aliso Canyon reliability issues as well as the feasibility of summer and winter installations. CESA submitted comments on April 22 advocating for the many advantages of energy storage in addressing LA Basin grid reliability issues and sharing that 22 MW and 225 MW could be operational by August 1 and December 1, respectively. To achieve this, CESA said that several ‘support actions’ are needed to accelerate new capacity and quickly re-purpose existing capacity.

See CESA's comments on April 22, 2016 on the Joint Agency Workshop

On August 22, 2016, a draft Winter Action Plan was released that included staff recommendations for additional near-term mitigation measures. Notably, the report concluded that the continued inoperability of the Aliso Canyon gas storage facility should not compromise Southern California's gas and electric reliability in the coming winter, barring extreme cold winter weather. The agencies assessed 12 scenarios – i.e., three types of weather conditions for each of four Aliso Canyon availability cases – and found that SCE, LADWP, and SDG&E should be able to replace lost gas-fired power generation if SCGs’ supply becomes constrained during winter 2016-2017, making blackouts unlikely. The report also highlighted 10 additional measures to “reduce, but not eliminate,” which did not include energy storage as a measure.

On August 26, 2016, a Joint Agency Workshop was held in Diamond Bar, CA to present a draft Winter Action Plan to preserve LA Basin reliability for winter 2016.

On January 17, 2017, the CPUC published its report on the Aliso Canyon gas storage facility's working gas inventory, production/injection capacity, and well availability for reliability. The analysis found that the current number of wells available, even assuming optimistic production rates, was not sufficient to assure reliability in the short term. As additional wells are tested and brought into service and with improved withdrawal rates, capacity requirements should, under current estimates, be able to be met. However, the timing is such that there will not be enough completed wells for the 2016-2017 winter season or the 2017 summer season. 

On January 31, 2017, the CPUC issued its Aliso Canyon Demand-Side Management Impact Summary. With electric demand in the LA Basin reaching 18,800 MW on a peak summer day, the CPUC estimated the impact of load reduction measures to be 676 MW: marketing and research (540 MW), accelerated deployment of energy storage (98.5 MW), and demand response (37.8 MW). Other mitigation policies include tightening of gas-balancing rules, reprioritizing existing energy efficiency, intensifying deployment of energy savings assistance program measures, and changing the CSI thermal program, which combined to reduce 49 million therms of natural gas. 

On December 11, 2017, the CPUC’s Energy Division published its final report on the Aliso Canyon working gas inventory, production capacity, injection capacity, and well availability for reliability. The report noted that there have been unprecedented levels of outages on the SoCalGas system, which posed winter system reliability risks. The report noted that it is likely that SoCalGas will withdraw gas from Aliso Canyon this winter in order to meet gas demand that cannot be met by gas from pipelines or other storage fields and thus authorized a greater range of gas inventory in Aliso Canyon to meet gas demand on a peak winter demand day (a 1-in-10 year cold day) as well as under “normal” conditions. In the meantime, SoCalGas continued to push for removal of some limitations on the Aliso Canyon facility to manage potential reliability issues in the coming winter based on its analysis. The Environmental Defense Fund (EDF) submitted a protest on November 20, 2017 that highlighted several deficiencies in SoCalGas’ analysis to begin further injections into the Aliso Canyon facility and offered suggestions designed to further strengthen the efficiency and reliability of the system. Specifically, EDF pointed to SoCalGas’ mistaken assumptions about the capacity of different storage fields and needed curtailment, and highlighted flaws in their claims that full receipts of supply are unrealistic and the need for winter period injections into storage to maintain inventory and deliverability.

On January 18, 2018, the California Council for Science and Technology (CCST) released its independent study on the long-term viability of underground natural gas storage in California and found that the risks associated with underground gas storage can be managed and, with appropriate regulation and safety management, may become comparable to risks found acceptable in other parts of the California energy system. CCST added that California’s energy system currently needs natural gas and underground gas storage to run reliably and that replacing underground gas storage in the next few decades would require very large investments to store or supply natural gas another way, which would come with its own infrastructural risks. CCST could not investigate the feasibility and impacts on reliability of closing one or more underground gas storage sites in the state while leaving the others open. Importantly, the study found that natural gas would be needed to meet generation needs in the winter, when there is reduced solar insolation and slower wind speeds, in a 2030 world with significant renewables to reach the state’s climate policies and goals. A major takeaway from this study would be that there is a major role for seasonal storage as a potential alternative to these underground natural gas facilities. This study was mandated by the California Legislature in 2016 and was conducted in an 11-month period in 2017.

On May 8, 2018, a joint agency workshop was held that included staff presentations Southern California reliability issue updates and tracking progress on conventional generation, preferred resources, transmission upgrades, and contingency mitigation measures related to the Aliso Canyon gas storage facility limitations. The CEC plans to address these issues as part of the 2018 IEPR update. The CEC and SoCalGas also presented on the reliability issues associated with natural gas pipeline outages and the assessment and actions being taken to address energy reliability.

On August 28, 2018, a CCST workshop was held to discuss their comparative analysis on the risks of individual gas storage fields, as well as the impacts of these fields on public health and grid reliability.

On December 6, 2018, the CPUC staff also published a report on natural gas and electric system operations in Southern California from November 2017 through March 2018. During this winter period, the CPUC found high gas reliability risks attributed to transmission pipeline outages and post-leak restrictions on Aliso Canyon usage. These high risks were mitigated in part by unusually warm weather conditions in Southern California, which kept demand for natural gas low. However, the CPUC concluded that SoCalGas’ use of storage and system operations during this time were warranted and followed the established Withdrawal Protocol.

On January 11, 2019, a joint agency workshop was held as part of the CEC’s IEPR proceeding to discuss the topic of recently high natural gas prices in Southern California and potential solutions to reduce the spread between SoCal Border and SoCal Citygate prices. The potential solutions could impact this proceeding.

On April 2, 2019, SoCalGas submitted a Summer 2019 technical assessment reporting that the increased pipeline capacity has positioned the SoCalGas system to be in better reliability position in the “best case” for the upcoming summer months as compared to last summer but could still face insufficient storage inventory heading into the next winter.

On May 10, 2019, the CPUC published a report on SoCalGas’ conditions and operations in Winter 2018-2019, which were found to be largely similar as the previous winter due to ongoing pipeline maintenance, reduced capacity at Aliso Canyon, and the Aliso Canyon Withdrawal Protocol still in effect. Price volatility was also a concern heading into the winter. An early warm winter mitigated the need to rely on Aliso Canyon, but a prolonged stretch of cold weather and inaccurate weather forecasts in the late winter led to gas price spikes in the SoCal Border and SoCal Citygate markets. Non-Aliso inventory levels decreased by 61% from the start of the winter to handle this volatility. Importantly, the report found that SoCalGas followed the protocols and highlighted how gas storage plays an important role on system ramping hours and on electricity prices.

On May 23, 2019, a joint CPUC-CEC workshop was held on energy reliability in Southern California related to the Aliso Canyon issue. A key discussion issue was the pipeline outages and repairs faced by SoCalGas, which has limited the flexibility and operations of the gas system. SoCalGas defended against criticism from the joint agencies and LADWP that the pipeline repairs and replacements are taking longer than similar types of work elsewhere, noting that not all pipeline projects are similar.

On August 2, 2019, a webinar was held to describe the methodology and results of a Root Cause Analysis into the SoCalGas’ Aliso Canyon leak. Blade Energy Partners, an independent engineering firm, was selected to perform this analysis by the CPUC and the Division of Oil, Gas, and Geothermal Resources (DOGGR).

On June 20, 2019, a workshop was held to discuss preliminary results of the economic, hydraulic, and production cost modeling. SoCalGas commented on the preliminary analysis, focusing on how historical analysis is needed on the CPUC staff difference-in-difference economic analysis since PG&E customers cannot be the control group and on concerns about assumptions of unachievable and unrealistic flowing supplies in the hydraulic analysis – i.e., the interaction between receipt points and networked nature of transmission system must be considered.

On September 20, 2019, the CPUC Executive Director issued a letter on that reported on the concerning low inventory levels at the non-Aliso gas storage facilities, which is due to specific areas of pipeline maintenance reducing pipeline flow capacity and the insufficient build up in inventory at these facilities. As a result, the CPUC directed SoCalGas to increase injection capacity at all its storage fields to ensure winter reliability.

On December 6, 2019, Resolution G-3560 was issued that directed SoCalGas to make temporary modifications to allow more underground gas storage injection capacity to be made available to storage customers due to low inventory levels and concerns of reliability risks in Winter 2019-2020.

On April 1, 2020, SoCalGas prepared a technical assessment to provide a forecasted outlook of system reliability during the coming 2020 summer months based on analysis of pipeline capacity available to bring gas into the system, forecasted summer demand, available system capacity to serve demand, forecasted storage inventory for the following winter season, and various existing and potential outages and the operating restrictions on gas transmission and storage assets. With or without the use of Aliso Canyon, SoCalGas reported that it has sufficient capacity to serve the forecast summer peak demand of 3.32 BCFD under the “best case” supply scenario, but insufficient capacity to serve the forecasted summer peak demand of 2.97 BCFD under the “worst case” supply scenario. SoCalGas also found that the current maximum allowable system storage inventory of 84.4 BCFD can be reached by November 1, 2020 (as specified by the Aliso Canyon Withdrawal Protocol) under a “best case” supply scenario assumption. However, under a “worst case” supply scenario assumption, available supplies are insufficient to meet forecasted demand through the summer season, resulting in non-core curtailment over the season even with all storage fields completely depleted by the end of the season.

On April 15, 2020, the CPUC published a 2020 summer reliability assessment report for Southern California, reporting that the gas system approaches summer in better condition than at the same time last year, with more gas in storage and an additional gas transmission line in service. As of March 31, 2020, SoCalGas’ non-Aliso storage fields were approximately 67% full, up from 45% last year. SoCalGas was also able to draw down the four fields in a more balanced way in 2020 compared to 2019 due to an additional gas transmission line becoming back in service (Line 235-2), which had been out of service since October 2017. Contrary to SoCalGas’ report, the CPUC’s findings showed that non-Aliso withdrawals would be sufficient to meet demand under both best-case and worst-case scenarios at the daily level, though hydraulic modeling of hourly demand was not performed.

TPP Special Study

The CAISO affirmed that significant risk remains, with this summer still not being over and it being unknown when the safety review will be completed. A special study in the 2016-2017 TPP looked at gas-electric coordination issues for summer 2017. The study examined four scenarios that looked at different supply shortfalls between scheduled and actual gas flows. The most critical reliability concern is post-transient voltage instability, which can be mitigated by timely additions of planned dynamic reactive supports. These planned transmission projects, however, are under construction and cannot be in service until December 2017 at the earliest. The CAISO also identified thermal loading concerns in the LA Basin.

The CAISO plans to perform a longer-planning horizon reliability assessment through summer 2026, which will include the CPUC-approved energy storage projects as well as other resource and transmission project assumptions. These results will be presented in November 2016.

SDG&E 2016 Aliso Canyon Energy Storage Procurement

Developed in response to Resolution E-4791, SDG&E contacted qualified respondents in its ongoing 2016 Preferred Resource Local Capacity Resource RFO, which solicited both turnkey and third-party-owned systems, to determine if expedited energy storage projects could come online by the end of 2016. 

On July 18, 2016, SDG&E announced awards to two AES Energy Storage projects for a total of 37.5 MW of RA capacity to be sited within existing substation property. Two identical Engineering, Procurement, and Construction (EPC) contracts have been awarded for a 30-MW, 4-hour project and a 7.5 MW, 4-hour project, both of which will be owned by SDG&E and operated and maintained by AES (with performance guarantees). The projects will be online by January 31, 2017.

On August 19, 2016, Resolution E-4798 was issued that approved Advice Letter 2924-E for 37.5 MW of energy storage projects. The projects are contracted to meet the targeted online date.

Relatedly, SDG&E submitted an Advice Letter to approve its proposed tracking mechanism for local San Diego sub-area 2017 RA capacity costs due to concerns regarding the availability of the Aliso Canyon gas storage facility. Local RA obligations have thus shifted from the LA Basin to the San Diego sub-area. D.16-06-045 identified 865 MW of incremental need for the local San Diego sub-area due to Aliso Canyon.

SoCalGas Injection Plan & Withdrawal Protocols

On June 30, 2017, the CPUC issued Resolution G-3529 that approved SoCalGas’ proposed gas storage Injection Enhancement Plan but denied temporary modifications to the System Operator Injection Capacity Limits in an effort to maintain summer reliability through September 30. Specifically, the Resolution would allow SoCalGas to increase and maximize storage injection at facilities other than Aliso Canyon. This is in response to SoCalGas’ letter to the CPUC on April 28 that expressed concern that the system’s physical ability to provide reliable service on peak demand days and response to abnormal operating conditions is at risk. 

On July 19, 2017, the CPUC approved the re-opening of the Aliso Canyon gas storage facility and allowed for a withdrawal rate of up to 2.43 BCF per day in the winter and 2.46 BCF per day in the summer to be used in times where there is an electrical reliability threat. The upper bound of gas storage inventory for Aliso Canyon is now up to 23.6 BCF, meaning that 8.8 BCF of natural gas will likely be injected into the facility. While contentious, this stabilizes the gas system considerably in the LA area for the time-being.

On July 21, 2017, CEC Chair Robert Weisenmiller released a letter urging the CPUC to plan for the future closure of the Aliso Canyon gas storage facility. On the same day, the City of Los Angeles announced that they will file suit to stop the reopening of Aliso Canyon. Governor Brown has also stated on the record that Aliso Canyon should be retired from service.

On October 17, 2017, the CPUC and CEC Commissioners submitted a letter to SoCalGas instructing SoCalGas to identify mitigation measures for reliable service during the winter.

On October 30, 2017, SoCalGas issued a response letter that pushed back against the CPUC and CEC Commissioners for not including “enhanced reliance” on Aliso Canyon as part of the mitigation measures, citing how the facility has been subjected to months of rigorous inspection and has been safely operational for many months. SoCalGas also expressed their concern with the continued limitations on the facility (i.e., withdrawal protocols, curtailment rules) and use of the facility as a last resort despite potential energy risks in the winter.

On March 30, 2018, CPUC issued a letter to SoCalGas directing it to immediately begin maximizing gas storage injections because the overall storage inventory levels are critically low for the upcoming spring.

On May 11, 2018, the CPUC issued Resolution G-3540 that approved SoCalGas’ request for its Second Injection Plan to maintain summer 2018 reliability by continuing to implement temporary modifications to increase storage injections and increase storage injection capacity available to the market. However, Resolution G-3540 denied SoCalGas’ request to increase the allowable inventory and modify the withdrawal protocol to allow for more flexible use of Aliso Canyon to manage storage inventories. Since the approval of the First Injection Plan, SoCalGas’ systems have suffered several pipeline outages, placing additional stress on the system to necessitate urgent storage injection, especially as its other fields were critically low in inventory during a several week period in February and March where there were below-average temperatures in the SoCalGas territory. As I.17-02-002 proceeds, the CPUC is proposing to allow for temporary injections to help SoCalGas to get through the summer months but denied any “longer-term” modifications to allow for increased reliance on the gas storage facility.

On June 29, 2018, the CPUC issued its update to the 715 Report and a corresponding letter that recommended that the maximum allowable Aliso inventory be increased from the current 24.6 Bcf to the proposed 34 Bcf due to continuing pipeline outages on the SoCalGas system, consideration of the impact that declines in inventory at non-Aliso fields have had on withdrawal capacity, examination of whether 1-in-10 peak day demand can be met at forecasted inventory levels, and limited injection capacity at non-Aliso fields. Unlike previous reports, this update also looked at both summer 2018 and winter 2018-2019, not just the coming season, and reflected declines in gas storage inventory and withdrawal capacity at non-Aliso fields in conducting its assessment on what is required to manage Southern California gas reliability over the short term. Finally, the report noted that, as of May 31, 2018, 46 wells completed all testing and remediation requirements and were operational at Aliso Canyon. Note that SB 380 added Section 715 to the Public Utilities Code that requires the CPUC to determine the range of Aliso Canyon inventory necessary to ensure safety, reliability, and just and reasonable rates.

Parties who commented on the draft report focused their concerns on the three SoCalGas transmission pipelines that continue to be out of service, resulting in reductions in gas receipts into the LA Basin. Porter Ranch Neighborhood Council (PRNC) and the County of Los Angeles suspected that SoCalGas is “slow-walking” repairs that have necessitated increased inventory at Aliso Canyon, leading them to recommend that the CPUC investigate the pipeline outages and repairs and to direct action by SoCalGas to fix this situation more quickly. PRNC also recommended that the determination on whether to increase inventory levels of Aliso Canyon could wait until the low-demand months in the fall to meet winter 2018-2019 reliability needs, creating an opportunity for the CPUC to direct action against SoCalGas on pipeline fixes, while the County of Los Angeles went further and recommended penalties or removal of the pipelines from the ratebase.

In sum, the CPUC found an urgent need to rely on Aliso Canyon in the short-term due to “extensive” pipeline outages that limit imports of gas that would be stored in non-Aliso fields, making Aliso Canyon a more critical resource. This situation raises some flags, but ultimately the key assessment will be conducted in I.17-02-002 where the long-term need and feasibility of Aliso Canyon will be determined, whereas the PUC Section 715 Report is intended to assess short-term reliability needs.

On August 10, 2018, SCE filed an expedited motion to seek expedited action by the CPUC to ameliorate the sharp spikes in SoCalGas gas prices driven by the application of SoCalGas’ Tariff Rule 30 Operational Flow Order (OFO) non-compliance charges. This effect was observed to be particularly acute during periods of high temperatures that have coincided with a period of restricted operations at the Aliso Canyon natural gas storage facility and current capacity reductions of SoCalGas’ transmission pipelines. Specific action requested by SCE is that CPUC cap the OFO non-compliance charges to address the price spikes to electric and gas retail customers, which will not enhance or adversely impact reliability. SoCalGas, however, opposed this Motion because they said it was outside the scope of I.17-02-002.

On July 23, 2019, the CPUC staff issued a proposal to revise the Aliso Canyon Withdrawal Protocol to help address energy reliability challenges and price impacts in Southern California. The CPUC has witnessed increased scarcity of gas supply caused by pipeline outages and the operational restrictions of Aliso Canyon. Thus, the revisions are intended to help preserve inventory levels at the non-Aliso storage fields, increase their corresponding withdrawal capacity, and enable those fields to supply gas when needed at critical hours of peak customer demand. Specifically, the CPUC staff proposal specified that withdrawals from Aliso Canyon would be allowed if any of the following conditions are met:

• Preliminary low Operational Flow Order (OFO) calculations for any cycle result in a Stage 2 low OFO or higher for the applicable gas day.

• Aliso Canyon is above 70% of its maximum allowable inventory between February 1 and March 31; in such case, SoCalGas may withdraw from Aliso Canyon until inventory declines to 70% of its maximum allowable inventory.

• The Honor Rancho and/or Goleta fields decline to 105% of their month-end minimum inventory requirements during the winter season.

• There is an imminent and identifiable risk of gas curtailments created by an emergency condition that would impact public health and safety or result in curtailments of electric load that could be mitigated by withdrawals from Aliso Canyon.

New Gas Connections

On December 15, 2017, Draft Resolution G-3536 was issued that proposed to require SoCalGas to implement an emergency moratorium on new commercial and industrial natural gas service connections in both incorporated and unincorporated areas of Los Angeles County area from January 11, 2018, until further Commission action, or March 31, 2018, whichever is earlier. This response was made in response to the Aliso Canyon Winter Risk Assessment Technical Report for 2017-2018, which identified an emergency moratorium on new connections as a potential measure to avoid increased demand for natural gas and to avoid gas service disruptions to existing customers in the event of a colder than normal series of days in the winter.

On February 22, 2018, Draft Resolution G-3536 was withdrawn because multiple business associations and gas-related parties opposed the moratorium due to the impact on new businesses, projects, and economic development, which may rely on getting new gas service extensions. Others protested on the grounds that the resolution provided extremely short notice to adjust. A few parties, such as Sierra Club, supported the proposal as advancing the state to greater end-use electrification.

SoCalGas DR Program Application (A.18-11-005)

On November 6, 2018, SoCalGas filed an application to implement three DR programs for natural gas ($50.6 million budget) use during times of anticipated system stress:

• Four DR Pilots will focus on load control programs for space and water heating for residential customers and non-residential customers, a commercial and industrial load reduction program, and a behavioral messaging program.

• Gas DR Emerging Technologies Program will test new technologies for gas equipment to support potential future gas DR efforts.

• Winter Notification Marketing Campaign will incorporate an over-arching communication campaign throughout the winter season and a notification component to support reducing gas usage in response to DR events that are called or during periods of anticipated system stress.

These program proposals will support a continuation of previous DR efforts that supported SoCalGas during the 2016-2017 and 2017-2018 winter seasons.

Investigation to Minimize/Eliminate Aliso Canyon (I.17-02-002)

Background

On May 10, 2016, Governor Brown signed into law SB 380, which directed the CPUC to open a proceeding by July 1, 2017 to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility. The CPUC has jurisdiction over the above-ground infrastructure beginning where Aliso Canyon connects to the pipeline (or at the wellhead) as well as over the recovery of costs related to the facility. 

On February 17, 2017, the CPUC approved a Decision to open an Order Instituting Investigation (OII) to determine the feasibility of minimizing or eliminating the use of the Aliso Canyon gas storage facility, pursuant to SB 380. SoCalGas, the operator of Aliso Canyon, is named as the respondent to this OII. The OII calls for a two-phased approach. In Phase 1, the CPUC will investigate whether it is feasible to reduce or eliminate the use of Aliso Canyon while maintaining electric and gas reliability for the region. The Phase 1 analysis will include an assessment of energy cost impacts, electric/gas reliability impacts, viability of alternatives, and safety implications. Phase 2 will take into consideration the results of the Phase 1 analysis to identify the conditions, parameters, and timeframe of reducing or eliminating the use of Aliso Canyon, if determined prudent to do so. Workshops to determine the scope of Phase 1 will be held in the summer of 2017, with the Phase 1 study completed in the winter of 2017. Phase 2 will occur across the first half of 2018, and a final decision is expected in mid-2018. Overall, the CPUC has slated a 24-month timeframe from opening of the proceeding to complete all the work.

Energy storage procurements could result from this OII, and CESA will track the new proceeding closely as necessary. CESA supported the Investigation and recommended that it quantify the costs of past and future methane gas mitigation in the analysis. CESA also recommended that the CPUC model the potential closure of the Aliso Canyon gas storage facility in IRP system modeling.

See CESA's response on March 9, 2017 on the Aliso Canyon OII

On June 27, 2019, similar to the investigation into PG&E’s governance, an OII (I.19-06-014) was issued to determine whether the organizational culture and governance of SoCalGas and its parent company, Sempra Energy, prioritize safety and adequately direct resources to promote accountability and achieve safety performance goals, standards, and improvements. The CPUC may consider revising existing or imposing new orders and conditions on SoCalGas or Sempra Energy, as necessary and appropriate, to optimize public utility resources and achieve operational and safety performance record required by law, and to promote a high-functioning safety culture that promotes continuous safety improvement. The OII cited the natural gas leak related to its Aliso Canyon storage facility and a subsequent gas-line explosion as some of the reasons for this OII.

Phase 1 (Modeling Scenarios)

On March 10, 2017, the CPUC issued an OII to determine whether the Aliso Canyon gas storage facility has remained out of service for nine consecutive months, and if so, whether the CPUC should disallow all costs related to Aliso Canyon to be recovered through rates by SoCalGas. This is a very specific investigation that CESA will just track at most.

On April 17, 2017, a prehearing conference was held in Los Angeles, CA to discuss the issues, scope and scheduling of the formal proceeding, the relationship of this proceeding to other Commission proceedings, and to address any outstanding motions. A number of local communities and environmental organizations attended the PHC. Multiple stakeholders recommended that the scope be expanded to include health and other broad impacts and that the hydrology studies should be done by an independent consultant. Various parties differed on whether to consolidate or phase this proceeding. Notably, SoCalGas, Coalition of California Utility Employees (CUE), and the CAISO all supported the scope and schedule.

CESA attended the PHC to support the OII. CESA pointed to the success of the Aliso Canyon energy storage procurements and the introduction of SB 801 as reasons to include reliance on local energy storage deployment as a near-term mitigation measure in any assumptions and scenarios.

On May 17, 2017, EES Consulting presented its study, which was contracted by LA County to evaluate the alternatives that would mitigate or eliminate the need to withdraw gas from the Aliso Canyon gas storage facility during the summer of 2017 and winter of 2017-2018. Some of the key findings in the assessment include:

• Mitigation measures are proving to be successful in reducing the overall demand for gas and therefore gas withdrawals from Aliso Canyon should not be necessary in the summer of 2017

• The increase in hydroelectric generation due to the wet season should but some time for additional mitigation measures

• There are not sufficient wells available at Aliso Canyon to withdraw gas to meet peak summer demand

On June 20, 2017, a Scoping Memo was issued that will outlined the scope of studies to be conducted in this investigation, including:

• Hydraulic modeling (gas and electric reliability): These models simulate the impact of hourly changes in gas supply and demand on pressures in the pipeline network. Hydraulic modeling has been used previously for the Aliso Summer and Winter Technical Assessments.

• Production cost modeling (electric costs and reliability): These models estimate the production costs and expected reliability of a particular electric system over a given time period. The availability of gas storage can impact nearby electric generation due to gas’ relatively slow transport speed.

• Economic modeling (gas prices for residential/commercial customers): Storage is used to reduce the economic impact of fluctuations in natural gas prices and to help moderate costs during temporary price spikes, which typically occur during extreme weather events. Since gas is a pass-through cost, loss of storage could increase customers’ exposure to market volatility.

The Scoping Memo also highlighted the two overarching questions of this proceeding:

• Is it feasible to reduce or eliminate the use of the Aliso Canyon Natural Gas Storage Facility while still maintaining electric and energy reliability for the region?

• Given the outcome of Question 1, should the Commission reduce or eliminate the use of the Aliso Canyon Natural Gas Storage Facility, and if so, under what parameters?

The CPUC plans on two phases for the proceeding. In Phase 1, the CPUC will undertake a comprehensive effort to develop the appropriate analyses and scenarios to evaluate the impact of reducing or eliminating the use of Aliso Canyon with a goal to develop models that understand the impacts of reduction or elimination of the facility. Phase 1 will be resolved by the issuance of an Assigned Commissioner’s Ruling, likely in November 2017. Phase 2 will begin in Q1 2018 and will evaluate the impacts of reducing or eliminating the use of Aliso Canyon using the scenarios and models adopted in Phase 1.

On June 26, 2017, a Ruling was issued on June 26 that attached the CPUC Energy Division’s Initial Phase 1 Scenarios Proposal for feedback and discussion at an August 1, 2017 workshop. The initial models are intended to set a baseline on the need for Aliso Canyon for reliability and the cost to the system of various Aliso Canyon inventory levels if the gas and electric systems continue to operate close to the planned status quo, which includes all increases in renewables, conservation, and energy efficiency currently required by California legislation. These baselines will be critical in determining the cost and viability of long-term alternatives to Aliso Canyon.

On August 1, 2017, the CPUC held a workshop in Los Angeles, CA to provide an overview of its Initial Phase 1 Scenarios Proposal for its production cost, hydraulic, and economic modeling.

On April 4, 2018, a Ruling was issued that announced a CPUC contract with Los Alamos National Laboratory to oversee and independently evaluate hydraulic modeling to be conducted by SoCalGas while the CPUC Energy Division undertakes the production cost modeling and economic modeling efforts as part of the Phase 1 Scenarios Framework. The inability to find an external contractor to conduct the hydraulic modeling led to the CPUC opting to allow SoCalGas, which has the internal technical expertise, to conduct the necessary work with the oversight of a third party in order to mitigate conflict-of-interest concerns. Similar failed attempts to find a third-party contractor to conduct the economic and production cost modeling led to the CPUC assessing and affirming that it had the internal bandwidth and capabilities to do this work in-house. This is not ideal, especially as SoCalGas has pushed hard for re-opening Aliso Canyon, so CESA will continue to monitor this initiative closely to ensure fair and unbiased outcomes in the Phase 1 scenario analysis.

On May 23, 2018, a Ruling was issued that updated the Phase 1 schedule now that SoCalGas has been determined to conduct the hydraulic modeling with Los Alamos National Laboratory overseeing the process and the CPUC Energy Division has been announced to undertake the economic and power production modeling for the Phase 1 analysis. The assumptions and scenarios developed in Phase 1 will be used to conduct the actual analysis in Phase 2.

On June 15, 2018, a Ruling was issued that circulated an updated Phase 1 Scenarios Framework for informal comment and feedback. The updated framework maintained the three types of modeling that will be conducted in this proceeding: hydraulic, production cost, and economic. CESA’s main interest in this analysis will be in identifying whether alternatives to Aliso Canyon reliance in the form of increased energy storage deployment could be feasible. Thus, CESA was supportive of Sierra Club’s concern that the analysis does not recognize demand reduction as a tool to eliminate or minimize reliance on Aliso Canyon, as the demand inputs in the production cost modeling do not vary. Along those lines, CESA will focus our involvement in this proceeding on ensuring that the modeling accurately reflects future grid conditions, such as assuming retirements of plants that would reduce reliance on Aliso Canyon. If models reflect these two points, CESA believes that the results may highlight the role of energy storage in eliminating or reducing the reliance on Aliso Canyon.

The key analysis task for the hydraulic modeling is to determine the minimum level of gas in the underground gas storage facility needed to maintain reliability of both the electricity and gas systems and to maintain reasonable rates, with preference given to operations of non-Aliso Canyon gas storage facilities to determine whether closing Aliso Canyon would be feasible. The framework will take a “graded approach” where full monthly analysis will be completed for 2019, 2024, and 2029 for the peak winter and summer months. The operating conditions will be run under 1-in-10-year and 1-in-35-year scenarios, where no curtailment of gas load is allowed in the former and curtailment of all non-core gas load is acceptable in the latter. In informal comments submitted on June 28, 2018, many parties (Magnum, Southern California POUs, CAISO, SoCalGas) focused on some of the assumptions about the operational capabilities of the SoCalGas system that were either overly optimistic or not tied to historical performance. For example, the assumed 95% receipt point utilization rate should be closer to 80% and the assumption to study a single unplanned outage of pipelines or gas storage facilities should be expanded to study multiple outages, given historical receipt point utilization rates and historical/current outage rates.

In coordination with the hydraulic modeling, the production cost modeling (PCM) efforts will test the effects of electric system reliability and production costs due to the gas limitations found in the hydraulic modeling reliability assessment. Using the SERVM model and IRP assumptions, the PCM will reflect a reduced rate of gas delivery to 17 natural gas-fired power plants in the LA Basin served by the Aliso Canyon facility, which then affect their ramping ability, ability to start up on short notice, among other operating parameters. The power plants served by Aliso Canyon were highlighted below. It is important to note several plants below are OTC plants with compliance-based scheduled retirements, including several of SCE’s in the near term and many of LADWP’s in the long term (e.g., Scattergood units in December 31, 2024 and Haynes and Harbor units in December 31, 2029). According to its 2016 IRP, LADWP has put a hold on all planned local repowering projects to first conduct a system-wide independent analysis on the need and capacity for repowering these OTC plants.

The CPUC Energy Division will also simulate the effect of more distant gas delivery. Conversely, the inputs and outputs from the PCM analysis (e.g., expected hourly dispatch of electric generators) will be fed back into the hydraulic modeling. A “perform as found” scenario from the IRP where the system is unconstrained by natural gas curtailment will serve as the baseline that feeds into the hydraulic modeling. Loss of load expectation (LOLE) and total production costs will be used as measures of reliability and cost, respectively.

The goal of the economic modeling study is to estimate the impacts of reduction in Aliso Canyon gas storage on core natural gas ratepayers. Four analyses will be conducted:

• Natural gas price volatility impacts on natural gas customer bills

• Factors that motivate gas storage decisions

• Gas storage availability impacts on ratepayer bills

• Tighter gas supply impacts on power generation in outside of Southern California but in other parts of CAISO territory

In addition to the above modeling exercises, the CPUC will also conduct a feasibility assessment to determine whether minimum gas storage inventory levels can be maintained throughout the year (i.e., over a longer period of time). Generally, many parties had problems with the updated framework, with their critiques falling along the following themes:

• The assessment should not focus strictly on historic and current performance or conditions, but should reflect future expectations of grid conditions.

• Reliance on SoCalGas for many inputs in the modeling exercise and to conduct the hydraulic modeling raise potential conflict-of-interest concerns.

• Hourly hydraulic and production cost modeling is insufficient to assess potential reliability issues stemming from post-contingency ramping needed for the system.

• Scheduled shutdown of plants served by Aliso Canyon should be accounted for in the modeling scenarios.

• The study should use 2020 as the first study year instead of 2019 to increase usefulness since the study is expected to be completed in 2019.

• The study should expand beyond the CAISO balancing authority area to include other balancing authorities (i.e., LADWP, IID) that are affected by Aliso Canyon’s operations and potential closure.

Notably, SoCalGas offered a number of modifications to the framework that seem reasonable. For example, SoCalGas highlighted how the preference for non-Aliso storage fields does not reflect the CAISO’s economic dispatch requirements, how unplanned outages should not just focus on Aliso Canyon but also other non-Aliso gas storage fields, and how the production cost modeling should examine other plants beyond the 17 identified. Elimination or reduced reliance on Aliso Canyon would increase reliance on non-Aliso fields, which may impact the available gas supplies for a range of other gas plants in Southern California. In addition to these modifications, SoCalGas commented on the potential reliability risks of prioritizing interstate pipeline supplies over gas storage supplies and recommended that hearings be allowed before a Phase 1 decision. Meanwhile, the CAISO recommended that the framework incorporate its power flow modeling into the production cost and hydraulic analysis in a parallel analysis to determine the minimum generation requirement to meet local reliability needs, not just to identify the available gas as done in the CPUC’s proposed analysis.

On July 31, 2018, a technical workshop was held in Simi Valley, CA that discussed the Phase 1 scenarios for hydraulic, production cost, and economic modeling and solicited feedback from stakeholders. The CPUC staff explained that the reliability assessment will determine the minimum monthly inventory targets for underground storage at each facility to support system demand under stressed conditions (i.e., 1-in-10, 1-in-35) while accounting for pipeline transmission constraints. The model will determine needed withdrawals from non-Aliso fields before withdrawing from Aliso Canyon. If the analysis finds that Aliso Canyon withdrawals are needed, then the modeling will identify evaluate the impact of Aliso Canyon and non-Aliso outages and compute the required withdrawals from Aliso Canyon.

Several parties provided comments and recommendations during the workshop to improve the Phase 1 assessment. The CPUC made several changes in response to stakeholder comments, such as the use of 2020 instead of 2019 as the near-term study year, and feedback was sought on whether modeling each month, modeling over the long term, and including certain historical time periods is necessary for the hydraulic modeling. The CPUC, however, responded that the consideration of non-gas solutions, such as energy storage and demand-side resources, is outside the scope of this Phase 1 assessment. The CPUC also explained that hydraulic modeling runs without Aliso Canyon are unnecessary because the current modeling will rely on non-Aliso fields first before withdrawing from Aliso Canyon. Finally, the CPUC tried to reassure stakeholders that there will be close oversight and verification from the CPUC and Los Alamas National Laboratory (LANL) as SoCalGas conducts the hydraulic modeling, which many stakeholders viewed skeptically as a major conflict of interest. As for the production cost modeling, the CPUC is considering several key questions to inform this modeling exercise. For example, the CPUC is trying to simulate the effect on flexibility in dispatch from electric generation resulting from more distant gas delivery when Aliso Canyon is unavailable, which could be done by reflecting increased startup times and/or decreased ramp rates.

On September 14, 2018, a Ruling was issued on September 14 that adopted the CPUC staff’s Final Phase 1 Scenario Framework on scenarios, assumptions, and models. As compared to the draft framework, the CPUC made the following changes:

• Utilized smart meter data to shape core gas demand

• Developed unconstrained gas supply scenario

• Developed minimum local generation scenario (i.e., forced curtailment of generation except for minimum amount necessary for LCR)

• Removed assumption that total gas receipts are 95% of total scheduled capacity.

• Derived synthetic profile for core gas load

• Changed plant operating parameters to implement gas constraints (e.g., restrict ramp rate, increase startup time, and extend startup profile to simulate scheduling in advance)

On October 9, 2018, comments were filed by parties that offered a number of recommendations to improve the framework. A recurring recommendation from the CAISO, CUE, and Magnum has been the need to model more than one planned and unplanned gas transmission or gas storage outage to study WECC-wide reliability since SoCalGas serves SDG&E customers as well, and to use 30-minute intervals to capture sub-hourly ramping issues. SoCalGas requested that the CPUC test sensitivities for changing future conditions, including for the possibility for using existing infrastructure to promote renewable natural gas and hydrogen, rather than just based on historical averages. Meanwhile, environmental parties such as EDF and Sierra Club offered comments that recommended that the CPUC adjust its flawed assumption of continued new investments in natural gas generation, consider a high-electrification pathway, clarify where demand reduction measures could eliminate the Aliso Canyon need, and identify other operational actions (e.g., market rule changes, grid operations, on-demand pricing) to reduce the Aliso Canyon requirements.

On January 4, 2019, a Ruling was issued that adopted the final scenarios with some modifications from the September 14, 2018 version of the framework, as summarized below. For hydraulic modeling, the key changes were:

• Reduced the number of simulations required for the Reliability Assessment from 12 to 9 per reliability standard for the near-term (year 2020): In other words, there will be 18 instead of 24 for 2020. The near-term Reliability Assessment will be performed every other month for the shoulder months and every month for the remainder of the year. No changes are made for the reliability assessment of years 2025 and 2030.

• Added a sensitivity analysis to the 1-in-10 Reliability Assessment that investigates full zonal utilization with or without an unplanned outage for the near-term and for a future year: The sensitivity analysis has two more simulations for a future year to be determined later based on production cost model results.

• Use of smart meter data to extract only one load profile shape that represents both the peak and the extreme peak: The profile shape would then be stretched using peak use and total daily use parameters to match forecasted peaks. Previously, CPUC staff intended to extract two shapes (highest demand for the 1-in-35 reliability standard and the 3rd highest for the 1-in-10 reliability standard). Smart meter data is appropriate because the highest demand resulting from the meter data is still lower than the 1-in-10 and 1-in-35 peaks and therefore provides a closer representation of those peaks.

• Developed an analytical framework to select the most plausible unplanned outage for the Reliability Assessment and how these outages will affect the Feasibility Assessment: The CPUC staff will determine the optimal outages to include based on this analysis.

• Introduced the “mass balance sheet” approach in the Feasibility Assessment while still keeping the methodology for a “full transient simulation”: This is because the “mass balance sheet” approach would yield correct results only if the bottleneck of the pipeline network system is the injection capacity at the underground storage facility. Otherwise, one must rely on historical data and make assumptions regarding the monthly injection capacities. This would also address concerns about the high number of simulations.

For production cost modeling, the key changes were:

• Added Expected Unserved Energy (EUE) and Loss of Load Hours (LOLH) to the list of metrics: This will add another metric, not just the Loss of Load Expectation (LOLE) metric, as originally proposed.

• Follow the all-electric generators in two levels of curtailment for electric generation in the Rule 23 curtailment protocol, C.1(2) and C.1(4): This would relax the 1-in-35 curtailment standard, as originally proposed, to be the most consistent with the “Minimum Local Generation” scenario.

• Updated the hydraulic modeling section to reflect a more detailed series of curtailment protocols for the hydraulic model: Rule 23 describes a sequence of curtailments of Dispatched Electric Generation, first attempting curtailment of only 40% of “Dispatched Electric Generation” during the summer months and 60% curtailment in winter months, with the added requirement that all electric curtailments need to be coordinated with the CAISO (Tariff Rule 23, section C.1(2)). If this level of curtailment does not alleviate overloading of the gas transmission system, a more stringent curtailment protocol is effectuated (Tariff Rule 23, section C.1(4)). The gas utility can curtail all electric generators, including “Dispatched Electric Generation” as well as non-electric non-core customers, followed by curtailing core customers, until the overloading conditions are resolved.

• Simulate 1-in-35 standard for electric generation curtailments with Rule 23 section C.1(2): This would involve curtailments of up to 40% to 60% of electric generation depending on the season relative to the Unconstrained Gas Scenario, while preserving those electric generators required to meet the FERC Local Capacity Area Resource Requirements. If that is not adequate to prevent exceeding maximum allowable operating pressure on the gas pipeline system, CPUC staff will then implement curtailment protocols in the hydraulic model from section C.1(4), preserving only the Minimum Local Generation from the power flow model and nothing else. This corresponds to the Minimum Local Generation scenario. Non-core non-electric gas demand will also be completely curtailed consistent with Rule 23 section C.1(3).

For economic modeling, the key changes were:

• Assume volatility exists and proceed with the volatility analysis without pre-assessment: The CPUC staff previously suggested using a pre-assessment analysis to see if volatility exists after the Aliso Canyon well failure.

• Use the daily commodity price (only) paid by core customers for both SoCalGas core customers in specific zip codes and core customers in specific zip codes in PG&E territory: Using other bill components are not relevant to the analysis of this proceeding.

• Removed the Congestion Rent Assessment and will only perform the Implied Market Heat Rate Assessment: The CPUC staff determined that, while Implied Heat Rate analysis can be performed using both historical data from CAISO and output data from the Production Cost Model for future forecasting, the Congestion Rent assessment cannot.

This concluded Phase 1 of this OII and commenced Phase 2 actual model runs. Given the novelty of this modeling exercise, the Ruling adopted a process whereby Rulings would be issued upon updates to scenarios, assumptions or inputs with opportunities for party comment and workshop input.

Phase 2 (Modeling Results)

On March 29, 2019, a Phase 2 Scoping Memo was issued that set the scope of issues as:

• System reliability and electric/gas rate impacts of reducing or eliminating the use of the Aliso Canyon natural gas storage facility

• Whether to authorize the reduction or elimination of the use of the Aliso Canyon natural gas storage facility based on factors such as safety reliability, rates, and clean energy goals

Notably, the Scoping Memo disagreed with comments from Sierra club that the CPUC consider actions to be undertaken to ensure the closure of the facility as being within the Phase 2 scope or within the statutory requirements of SB 380.

On November 13, 2019, a workshop was held to present the analysis performed to date in economic modeling, hydraulic flow modeling, and production cost modeling. First, the CPUC staff discussed the inputs to the downstream end of the pipeline network for the hydraulic analysis, including the development of gas demand and hourly demand profiles. Notably, based on its analysis, CPUC staff recommended that SoCalGas include a warming climate scenario or assumption in the California Gas Report. Second, the CPUC staff provided a status update on the two modeling outputs that feed into the PCM analysis. With the development of the Reference System Plan, this proceeding could forecast gas use (i.e., hourly gas demand shapes) from electric generation for each power plant out to 2030. Similarly, the power flow studies for summer and winter reliability from LADWP and CAISO would ensure that PCM keeps gas to run those local generation units from being curtailed. Third, the CPUC staff presented results for Step 1 (volatility) and Step 2 (difference in difference) of the econometric analysis. Since the Aliso event, SoCal City Gate and SoCal border natural gas prices have been more volatile. In 2017, same-day gas price increases of 25% became common, and in 2018, increases even greater than 25% became common. The risk and potential loss for natural gas buyers from these hubs increased in 2017 and 2018. In its difference-in-differences analysis of SoCalGas customers (treatment) and PG&E customers (control), the CPUC staff found that the average gas procurement cost from 2016-2018 increased by $1.82/bill after the Aliso incident, with higher levels in 2017 and 2018 due to the partial and full effect of pipeline outages.

On March 9, 2020, a Ruling was issued that provided an update that Synergi model has been retained to conduct part of the hydraulic simulation work and explained that it will conduct seasonal, not monthly, simulations to reduce the number of runs, given the general similarities across months in a season. Staff also explained that the non-Aliso storage fields will likely be full regardless of month and that gas system design standards are established annually.

Phase 3 (Replacement Scenarios)

On December 20, 2019, a Phase 3 Scoping Memo was issued that requested party input on the baseline analysis and cost estimates for replacement scenarios in order to study the merits of closing Aliso Canyon. Sierra Club, particularly, questioned the baseline analysis for not including building electrification as reducing gas demand while others commented on the need to quantify the benefits of Aliso Canyon closure and to model the potential of DERs to provide the type of electrical services that gas plants currently do. SoCalGas emphasized the current risks of reliance on out-of-state natural gas deliveries without Aliso Canyon gas storage and highlighted the IRP modeling findings that there are reliability risks associated with a future of solar and storage. The Southern California POUs and many others also echoed the need to ensure that Phase 3 inputs and assumptions are aligned with those from Phase 2 as part of this investigation’s analysis as well as the IRP assumptions, though the modeling results there need to be improved (i.e., with specific, not generic, resources)

Power Charge Indifference Adjustment Mechanism (R.17-06-026)

PCIA Overview

The Power Charge Indifference Adjustment (PCIA) ensures that the above-market costs of generation-function energy storage are recovered from those for whom the resources were procured. The PCIA is a rate applied to customers who choose to receive electric commodity service from third-party service providers, such as community choice aggregators (CCAs) or energy service providers (ESP) serving direct access (DA) load, to ensure those customers continue to pay their proportion of above-market costs associated with resource commitments made by the utility on their behalf before their departure. Essentially, it protects bundled customers from financial harm due to load departures and is intended to maintain bundled customer indifference by ensuring that above-market costs associated with prior resource commitments are not shifted from departing load customers to the utility's bundled customers. Bundled customers pay their proportion of above-market costs through the utility's generation rate. 

Each IOU calculates vintaged PCIA rates on an annual basis in its Energy Resource Recovery Account (ERRA) forecast application. Generation resources and departing load customers are assigned a "vintage" based on the year the resource is committed and the customers' departure date, respectively, to ensure that departing load customers are appropriately charged/credited for the above- or below-market costs of generation resources procured on their behalf prior to their departure. For each vintage year:

Indifference Amount = Forecasted Portfolio Costs - Market Portfolio Value

where Portfolio Costs include "vintaged" utility-owned generation, PPA contracts, capacity contracts, etc. and Market Portfolio Value includes capacity value, energy value, renewable adder, etc.

Annual forecast generation costs are compared to the forecast market value of the generation portfolio. These above-market costs become stranded when customers depart bundled utility service (i.e., departed load) unless departing customers pay their fair share of those above-market costs. These costs are shared by current and departed customers from that vintage year. 

Indifference amounts represent the total above-market cost of the vintaged portfolio (i.e., the total to be collected if all customers depart bundled service) and are allocated to rate groups based on a "Top 100 Hours Allocation" - i.e., rate group contributions during the top 100 hours of IOU system demand (similar to generation allocators determined in GRC Phase 2 proceedings). 

The IOUs conclude that no adjustment to the PCIA methodology adopted in D.11-12-018 and Resolution E-4475 is necessary for storage procurement contracts. The IOUs see no difference in the generation aspect of energy storage resources versus a conventional gas generation resource. The IOUs propose the following protocols to include in the PCIA calculation for energy storage:

• Energy storage resources add to total portfolio costs based on fixed price of resource (contract), "fuel" costs associated with charging, and O&M

• Multiply forecasted portfolio generation, which includes the storage resource's MWh discharged to the market, by the energy component of the market price benchmark for each vintage year

• Multiply the portfolio net qualifying capacity (NQC), which includes the NQC of the storage resource, by the capacity value for each vintage year.

The CCAs disagree with the IOUs in that they believe that the PCIA calculation must be adjusted to incorporate energy storage. According to the CCAs, the same PCIA calculation for traditional generation resources should not apply because the CPUC has already recognized that energy storage is unlike any other generation resource (e.g., multi-functional, multi-domain) and because the energy storage market is rapidly evolving. The CCAs conclude that energy storage will not reflect the value of stranded resources. The IOUs' methodology does not capture system benefits, ancillary services, or reliability benefits, which will remain with the IOUs when customers depart from bundled service. As a result, either the PCIA should not apply, or adders should be applied to reflect these additional values. The CCAs are concerned that all energy storage contracts will be well-above market from the start given high capital costs and lack of valuation of the aforementioned adders in contracts. 

The CCAs conclude that energy storage will not reflect the value of stranded resources. The IOUs' methodology does not capture system benefits, ancillary services, or reliability benefits, which will remain with the IOUs when customers depart from bundled service. As a result, either the PCIA should not apply, or adders should be applied to reflect these additional values. The CCAs are concerned that all energy storage contracts will be well-above market from the start given high capital costs and lack of valuation of the aforementioned adders in contracts. 

Overall, this is a second-order Track 2 issue for CESA, and it will avoid the battle between the IOUs and CCAs on this matter. CESA has limited its comments on the PCIA to recommending a separate proceeding or track to focus on cost recovery issues. 

ERRA Forecast Overview

The purpose of the ERRA forecast is to forecast the energy production and costs from the IOUs' portfolio of generation resources. It sets the fuel and purchased power revenue requirement for bundled service customers, the new system generation (CAM) revenue requirement for all customers, and sets the PCIA and Competition Transition Charge (CTC) for departing load customers. The initial forecast is filed between April and June and an advice letter submitting relevant data for the Green MPB is filed on October 1. Updates to the initial forecast are filed in November. Revenue requirements and rates are effective January 1 or as soon as practicable upon receiving a final decision. 

The forecast is developed using proprietary models from the IOUs based on least-cost dispatch of its portfolio of resources using hourly forecasts of market prices and operating characteristics of resources. The energy forecasts for each resource are determined using model outputs for dispatchable resources and contractually expected deliveries for renewable and must-take (non-dispatchable) resources. Costs for each resource are determined using the sum of its fixed/capacity contract costs and model outputs for dispatchable resources and the sum of its fixed/capacity contract costs and contractually expected deliveries multiplied by contract costs for non-dispatchable resources. 

The November update is intended to refresh the generation resource portfolio for project expected online dates, success factors, and expected deliveries, for removal of contracts that are no longer expected to deliver in the next year, for the addition of newly executed contracts, and for updates to resources' NQC based on a CAISO report. Price forecasts for gas, GHGs, and power are also included based on the least-cost dispatch model. The same forecast methodology and tools used to set bundled customers' generation rate is used to set the PCIA. 

Phase 1

On June 29, 2017, this rulemaking was opened to review the current PCIA mechanism and will follow up and expand upon the recent consideration of the PCIA undertaken by participants in a workshop facilitated by Energy Division staff that issued a report in September 2016, and in the PCIA Working Group that issued a report this April. Participants in the PCIA Working Group identified three potential alternatives to the PCIA as it now exists: (1) a new portfolio allocation methodology (PAM); (2) a lump-sum buyout of what would otherwise be CCA customers’ PCIA obligations; and (3) the assignment of certain procurement contracts of the IOUs to CCAs in lieu of imposing the PCIA. This OIR will continue the work by the PCIA Working Group.

The preliminary scope of issues includes the following:

• Improving the transparency of the existing PCIA process

• Revising the current PCIA methodology to increase stability and certainty

• Reviewing specific issues related to inputs and calculations for the current PCIA methodology

• Considering alternatives to the PCIA

• Optimizing IOU portfolio management to minimize stranded costs

• Examining the status of exemptions from the PCIA for customers using California Alternative Rates for Energy (CARE) and Medical Baseline (MB) rates

• Implementing SB 350 regarding bundled customer indifference

In view of the approach and scope of this proceeding, the CPUC dismissed the Joint IOU Application (A.17-04-018) for approval of the Portfolio Allocation Methodology (PAM) for all customers until PCIA alternatives are considered in this proceeding. Consistent with its Policy Principles, CESA will monitor this proceeding and continue to avoid cost allocation issues.

On August 24, 2017, D.17-08-026 was adopted that granted the joint PFM of D.06-07-030 by the joint IOUs and CCAs that requires the IOUs to utilize a common PCIA calculation workpapers template in their respective annual ERRA forecast proceedings. The purpose of the common template is to improve transparency underlying the PCIA. This PFM was a direct outcome of the six-month PCIA Working Group from October 2016 to March 2017. 

On August 31, 2017, a Prehearing Conference was held. Key topics of discussion included data access/confidentiality issues and the applicability of the new PCIA to currently forming CCAs, which were proposed by certain stakeholders as additions to the scope of the proceeding. Various parties discussed the principle of whether only unavoidable costs should be included in the new PCIA mechanism, whether customers would be able to “buy out” their future PCIA obligations, and whether customers should be cost-neutral regardless of whether they are departing or bundled customers. There was also discussion on the number and appropriate scoping of tracks, need for workshops, and changing the categorization of the proceeding from quasi-legislative to ratesetting.

On September 25, 2017, the CPUC issued a Scoping Memo to set the scope, schedule, hearings and other procedural issues. Track 1 of the proceeding (PCIA Exemptions for CARE and Medical Baseline) will provide an opportunity for parties to submit briefs addressing the legal issues regarding exemptions from the PCIA for customers participating in the California Alternative Rates for Energy (CARE) program or who are served on medical baseline rates. Track 2 (Evaluation and Possible Modification of the PCIA Methodology) will examine the current PCIA methodology and consider alternatives to that mechanism.

On October 24, 2017, a workshop was held to provide a review of the current PCIA methodology, including the rate calculation and the Energy Resource Recovery Account (ERRA) forecast process. The workshop reviewed how the PCIA, per D.11-12-018, must:

• Adhere to the bundled customer indifference requirement

• Reflect current market value

• Be transparent while maintaining confidentiality

• Be administratively feasible

• Be durable and scalable to reflect changing markets

Challenges with the PCIA were discussed. First, the workshop discussed how the market price benchmark is flawed because it does not reflect forecasted or realized market prices for brown, green, and capacity values. As a result, the PCIA is only forward-looking and requires some sort of true-up to actual costs, actual volumes, and realized market prices. Second, workshop participants identified how the PCIA is not transparent as it uses administratively-set benchmarks that are not reflective of actual market prices, making it difficult to predict. Some participants highlighted how the benchmarks currently overstate market value and the process for updating the benchmarks is contentious.

On November 22, 2017, a Ruling was issued that directed parties in the proceeding to continue to work out issues around ensuring access to necessary data to enable parties to review and understand the current PCIA methodology. In doing so, the proceeding can move forward with developing any possible replacement methodology. This Ruling is the result of the IOU, CCA, and ESP parties failing to submit a report with consensus around various data access issues, as most areas remained “contested” or “open” issues. Without this initial policy resolution, the proceeding may just drag on and not be able to meet the proposed schedule.

On December 5, 2017, a second workshop was held that reviewed the current PCIA methodology. Importantly, the workshop discussed how 70-80% of the variation in the PCIA to date can be explained by changes in the market price benchmarks, primarily in the “Green Adder” derived from the newly-delivering IOU-contracted resources. Market prices of renewable energy credits (RECs) have dropped as renewable resources have been built under the RPS program. As load departures grow, the impact on bundled service customer bills grow based on how understated or overstated the benchmark is.

On January 16-17, 2018, a workshop was held to provide a forum for data-based discussion of cost responsibilities and going-forward solutions. Multiple parties submitted proposals and ideas for consideration, including the following:

• Commercial Energy proposed the creation of a “clearinghouse” whereby IOUs maintain all contracts, generating assets by contract bucket would be allocated in an auction, and PCIA is assessed on difference between contract and bid amounts.

• TURN submitted four different proposals that seek to: (1) reform the market price benchmark inputs to rely on actual market revenues instead of administratively-determined values; (2) cap the PCIA charge with a balancing account to track and recover any under-collections from CCAs in future years; (3) coordinate with the IOUs to engage in longer-term sales; or (4) have CCA voluntarily subscribe to IOU resources and be an off-taker for energy, capacity, and Renewable Energy Credits (RECs).

Phase 2

A second phase of this proceeding has opened and established a working group process to enable parties to further develop a number of proposals for further consideration.

On December 19, 2018, a prehearing conference was held to discuss how the CPUC will establish working groups to address the following Phase 2 issues:

• Benchmark true-up for RA and RPS

• Prepayment

• Portfolio optimization and cost reduction

• Allocation and auction

PG&E stated it would co-chair Working Group 1 (Benchmark True-Up) with CalCCA, SDG&E stated that it would co-chair Working Group 2 (Prepayment) with AReM and DACC, and SCE stated that it would co-chair Working Group 3 (Portfolio Optimization & Allocation/Auction) with CalCCA and Commercial Energy. An initial workshop will be held on March 1 to discuss benchmark true-up and other benchmarking issues (Working Group 1).

On February 1, 2019, a Scoping Memo was issued that memorialized and prioritized the scope for Phase 2 of this proceeding, with Working Group 1 issues to be resolved with the highest priority, Working Group 2 issues to be resolved in early 2020, and Working Group 3 issues to be resolved by mid-2020.

On December 16, 2020, an Amended Scoping Memo was issued that added the following issues to the Phase 2 scope:

• Whether to remove or modify the PCIA cap

• Whether to modify deadlines or requirements for Energy Resource Recovery Account (ERRA) and PCIA-related submittals and reports

• Whether to adopt a methodology for crediting or charging customers who depart from the utility service during an amortization period

• Whether to consider any other changes necessary to ensure efficient implementation of PCIA issues within ERRA proceedings

Cost Allocation Mechanism (CAM)

Background

The CAM is a cost recovery mechanism to recover costs from all benefiting customers and allocates resource attributes and net costs to all benefiting LSEs. The CPUC first adopted the CAM in D.06-07-029 and later refined it in D.11-05-005 as a mechanism for allocating net capacity costs to all benefiting customers. In this manner, capacity and energy are "unbundled" and the rights to the capacity are allocated to all LSEs in the utilities' service territory to be used towards each LSE's RA requirements. Customers receiving the benefit of this additional capacity pay only the "net costs" of the capacity through a "wires" charge, determined as a net of the total cost of the contract minus the energy revenues associated with dispatch of the resource. 

The "net capacity cost" for energy storage CAM resources are calculated as the costs resulting from the charging of each battery in the lowest-priced hours of a 24-hour period, which are netted against the revenues resulting from discharging that battery during the highest-priced hours in the same 24-hour period, to determine the net revenue received from the resource. That proxy for net revenue is then credited back to the contract cost to calculate the net capacity cost of the resource to be recovered through the New System Generation Charge from all delivery service customer

Power Charge Indifference Adjustment Mechanism (R.17-06-026)

Track 1 (PCIA Exemptions)

As part of Track 1 of this proceeding, the CPUC aims to address PCIA exemptions for CARE and Medical Baseline (MB) customers and will provide an opportunity for parties to submit briefs addressing the legal issues regarding those exemptions.

On February 20, 2018, opening briefs were filed with all parties generally agreeing that it is appropriate to eliminate the exemption because it has served its purpose of protecting CARE and MB customers from rate increases due to wholesale market price disruptions of the energy crisis. However, while the IOUs and ORA support the immediate removal of the exemption, the CCAs argued in favor of a phase out of the exemption to avoid abrupt bill increases.

On June 12, 2018, a PD was issued that resolved the Track 1 issues in this proceeding around current exemptions for certain departing load customers in IOU territories from paying the PCIA charge. The PCIA exemptions are eliminated for SCE’s and SDG&E’s departing load CARE and MB customers as well as CARE and MB customers of new CCAs. This was a fairly easy decision as few parties advocated for retention of PCIA exemptions, which was a legacy of the 2001 electricity market crisis aftermath where the CPUC sought to shield CARE and MB customers from rate increases arising from future wholesale market price disruptions. The CPUC directs the SCE and SDG&E to implement measures and outreach to avoid rate or bill shock but provides that the elimination of the exemption shall take effect immediately.

On July 2, 2018, comments were submitted with all parties in support of the broad determination to eliminate the PCIA exemption, but with the IOUs recommending minor modifications around timing and implementation issues. While supportive in general and despite outreach efforts directed in the PD, the CCAs, ORA, and Center for Accessible Technology (CforAT), recommended the PD be modified to allow the PCIA exemption for existing customers to be phased out over time to balance concerns about rate shock. ORA conducted bill impacts analysis that showed that affected customers could see up to $12/month increases in their bills if this decision is to take immediate effect.

On July 23, 2018, D.18-07-009 was issued that eliminated the PCIA exemptions for SCE’s and SDG&E’s departing load CARE and MB customers as well as CARE and MB customers of new CCAs. This was a fairly easy decision as few parties advocated for retention of PCIA exemptions, which was a legacy of the 2001 electricity market crisis aftermath where the CPUC sought to shield CARE and MB customers from rate increases arising from future wholesale market price disruptions. However, in contrast to the PD that ordered that the elimination of the exemption take effect immediately, D.18-07-009 responded to non-IOU parties’ comments that the exemption be eliminated by January 1, 2019. The decision determined that it is necessary to accommodate a customer notice period in advance of bill changes.

Power Charge Indifference Adjustment Mechanism (R.17-06-026)

Track 2 (Evaluation & Modification of PCIA)

On April 2, 2018, Phase 2 opening testimonies were submitted that addressed some of the fundamental questions around whether the current PCIA methodology represents cost shifts and whether alternatives should be considered. The CCA parties submitted a range of proposed ideas, such as establishing a voluntary buy-down program for PCIA-eligible power purchase agreements (PPAs) and adding a separate benchmark component to recognize the value of non-RPS GHG-free resources in the PCIA-eligible portfolio, among others.

On August 1, 2018, a PD was issued on that adopts revised inputs to the market price benchmark (MPB) that is used to calculate the PCIA (which will take effect on January 1, 2019), an annual true-up mechanism, and a cap that will limit the change of the PCIA rate from one year to the next. The true-up mechanism is intended to ensure that bundled and departing load customers pay equally for the above-market costs of PCIA-eligible resources, while the cap is intended to provide a degree of rate stability and predictability for CCAs and ESPs. Finally, the PD also adopted an option for these customers to pre-pay their PCIA obligation. The second phase of this proceeding is also opened to consider the development and implementation of a comprehensive solution to the issue of excess resources in utility portfolios, including possible voluntary, market-based redistribution mechanisms.

On August 14, 2018, an Alternate PD, authored by Commissioner Carla Peterman, was subsequently issued with several key differences, as shown below. Importantly, a key element of the PD is the 10-year limits on the inclusion of legacy utility-owned generation (UOG) (e.g., Diablo Canyon Power Plant) and energy storage costs in the PCIA. This limit is not included in the Alternate PD. The IOUs quantified the scale of post-2002 UOG in the IOUs’ portfolios during an oral argument held on August 2. Together the IOUs’ portfolios include approximately 8,122 MW of legacy UOG resources and 4,709 MW of post-2002 UOG, non-RPS contracts and long-term energy storage contracts, including 7,091 MW of Local RA resources that would be impacted by the PD’s limitations on departing load cost recovery for UOG. The 10-year limit on the cost recovery of energy storage through the PCIA presents a major risk to IOU procurement of energy storage, as they are no longer assured full cost recovery of these assets. The Alternate PD justified including UOG and energy storage costs in the PCIA because exclusion of these costs would cause bundled customers to bear these costs. Both annual true-up, similar options for departing customer rate impacts, cap, pre-payment options. Neither raises procurement costs or hinder goals., APD leads to increase in PCIA and decrease in bundled customer costs.

On August 21, 2018, opening comments were submitted on the PD. The CCAs favored the PD, as they argue that IOU will have proper incentives to manage their portfolio costs. The CCAs also contended with the IOUs failure to adequately forecast departing load, leading to over-procurement and stranded costs that CCA customers must then bear, and disagreed with having the costs of IOU contracts included in the PCIA after a CCA has provided clear notice of departure. The CCAs contended that collection of pre-2002 UOG stranded assets should have ended in 2001 – a limit that they claim to have been in place since 2004. The CCAs indicated that they have relied on UOG being termed out in their planning efforts. In the interim, some of the CCAs argue that the PCIA should be frozen at current levels to avoid cost shifts in either direction until Track 2 is completed.

Meanwhile, the IOUs favored the Alternate PD. They stressed that net costs of UOG and mandated energy storage procurement must be shared equitably by all customers, especially since these resources were procured on behalf of then-bundled customers, and discussed how the proposed PCIA “cost cap” is not equitable for IOU customers. The IOUs explained that concerns about smart management of portfolio are moot because portfolio management is reviewed by the CPUC and approved in GRCs. Additionally, the IOUs emphasized the need for additional clarity in the Alternate PD for the PCIA true-up mechanism, especially as it would apply to excess RA and RECs that the IOUs are unable to sell. The IOUs also recommended that the PD be changed to include pre-2002 and post-2002 utility-owned generation in the PCIA and to remove the PCIA rate collar since bundled service customers do not benefit from such a rate collar. The IOUs continued to push their GAM/PMM proposal that incorporates both a benefit allocation and a true-up to actual market results, which they argue improves on the PCIA by eliminating the volatile green benchmark and by having attributes and net costs follow load.

The CCAs were noticeably alone in their support of the PD. California Public Advocates (Cal PA, formerly ORA) supported the Alternate PD and expressed that CCAs can participate in Energy Resource Recovery Account (ERRA) proceedings to pressure IOUs to cost-effectively manage UOG facilities, but disagreed with both decisions in allowing for CCAs and ESPs to pre-pay their PCIA obligation without some true-up and refund mechanism to address inaccurate forecasts. ESPs also generally favored the Alternate PD but advocated for the use of real market prices (e.g., Platt’s index) instead of benchmarks.

On September 7, 2018, an all-party meeting was held to provide an opportunity for parties to discuss with CPUC Commissioners and the Assigned ALJ on their views of the two competing decisions. The IOUs stressed the need to prevent cost shift by adopting the Alternate PD and reiterated their views of removing the PCIA cap since it would lead to under-collection from departing load and a high cost burden on bundled service customers. However, the IOUs did not have a response to how they would address rate volatility of departing load.

The CCAs, on the other hand, warned of the rate impacts of the PD (142% increase of PCIA in 2019) and the Alternate PD (252% increase of PCIA in 2019), potentially causing them to go into “survival mode” and focus on short-term procurement, and advocated for smoothing rate impacts while still ensuring cost recovery. The CPUC Commissioners were not receptive to the CCAs arguing that the rate increases would make it difficult for them to serve DACs, implying that the CPUC would be harming DAC customers even though the CPUC has a concerted goal of supporting these groups. Commissioner Peterman countered that bundled customers should not be subsidizing the costs of the CCAs’ DAC and DER programs. For both decisions, the CCAs disagreed with the use of short-term RA values based on a limited dataset of RA contracts sold rather than also including UOG, backstop resources, and non-reported bilateral RA contracts. The CCAs argued that this dataset omits UOG, backstop resources, and non-reported bilateral RA contracts and thus only includes the “lowest value of RA” that represents only 10% of all RA compliance instruments used for 2019. The CCAs also disagreed with ascribing no avoided GHG value in the current PCIA. The CPUC Commissioners were unclear on what price could be used to set this GHG benchmark. They were not convinced that the IOUs retained hydro resources for their GHG value but for all the other values that could be operationalized with their retention.

The IOUs responded to Commissioner Peterman’s and ALJ Stephen Roscow’s request at the all-party meeting to provide their current forecasts of departing load by the end of 2018 and end of 2019, which revealed significant levels of load migration in the near term.

On October 19, 2018, D.18-10-019 was issued that approved the Alternate PD, which was more favorable for IOU procurement of energy storage since it would not impose limits on cost recovery for energy storage when procured by the IOUs. However, this PCIA decision was estimated to increase PCIA rates, which will impact load migration to the CCAs. The CPUC has estimated that the PCIA would lead to a bill increase for new CCA customers of 1.68% in PG&E’s territory, 2.5% in SCE’s territory, and 5.24% in SDG&E’s territory. Other guiding principles were adopted: 

• Resource Adequacy (RA): The RA adder shall be calculated using reported purchase and sales prices from IOU, CCA, and ESP transactions made during year n-1 for deliveries in year n. A zero or de minimis price shall be assigned for capacity expected to remain unsold.

• Renewable Portfolio Standard (RPS): The RPS adder shall be calculated using reported prices from purchases and sales of renewable energy by IOUs, CCAs, and ESPs transactions during the year n-2 prior to the forecast year n.

In addition, the decision modified the forecast benchmarks and required that the PCIA be trued up annually - a deviation from the PCIA historically, which was set purely on a forecast basis and not trued up. The actual above-market costs will now be tracked and be calculated based on resource costs (e.g., revenue requirement, contract payments, fuel and GHG expenses, firm transmission rights), attribute quantities (e.g., RA and REC revenues), energy and ancillary service revenues, revenues received from bilateral transactions, and billed customer revenues. 

On November 19, 2018, multiple applications for rehearing (AFRs) were filed on D.18-10-019, which the CPUC is not obligated to rehear:

• CalCCA argued that D.18-10-019 erred in failing to exclude the costs of utility-owned generation in the PCIA, failing to reduce the net PCIA portfolio costs of the IOUs by the value of any benefits that remain with bundled service customers, and failing to exclude PCIA portfolio costs that are not “unavoidable” or “attributable to” departing load customers – all of which they argue are contrary to statute. The CCA parties also discussed how they may pursue legal remedies through a petition for writ of review by an appellate court if not granted their application for rehearing.

• Marin Clean Energy (MCE), Peninsula Clean Energy (PCE), and Sonoma Clean Power (SCP) jointly filed a similar application that contended that the CPUC failed to enforce the mandates of the Procurement Policy Manual for the prudent management of the IOUs’ generation portfolio (e.g., avoiding over-procurement and conducting proper forecasting).

• Protect Our Communities (POC) made many of the same arguments as CalCCA and added that the elimination of the 10-year limit for post-2002 utility-owned generation shifts costs to departing customers and that the rate collar harms the viability of CCAs, especially as the cap will not be implemented until 2020. The POC also argued that the adopted benchmarks illegally fail to credit CCA customers for the full value of the IOUs’ long-term products.

• Shell contended that the CPUC does not have statutory authority to compel ESPs to disclose prices for the purpose of establishing a market price benchmark due to the limited CPUC authority by statute over ESP RA and RPS procurement, and that the CPUC failed to provide requisite notice that the CPUC would establish new transaction reporting requirements for ESPs.

• CLECA focused on the errors in the decision around the lack of “finding” around the IOUs’ use of consistent allocators or vintaging portfolio billing determinants.

Responses were subsequently filed, with many parties (IOUs, TURN, CLECA, CUE) recommending that the CPUC not grant their applications. TURN argued that the inclusion of utility-owned generation costs in the PCIA was consistent with statute and that concerns about the inclusion of any premium value of GHG-free resources would be captured in the true-up mechanism. The IOUs made a similar defense of the decision by citing how all customers should be responsible for a pro rata share of all relevant utility portfolio costs, as required by statute. They also recommended that the CPUC dismiss the application on the grounds that certain portfolio costs were avoidable, as the CPUC generally reviews procurement and contracts for reasonableness.

Power Charge Indifference Adjustment Mechanism (R.17-06-026)

Track 3 (Implementation)

A second phase of this proceeding has opened and established a working group process to enable parties to further develop a number of proposals for further consideration, including:

• Benchmark true-up for RA and RPS

• Prepayment

• Portfolio optimization and cost reduction

• Allocation and auction

On February 1, 2019, a Scoping Memo was issued that memorialized and prioritized the scope for Phase 2 of this proceeding, with Working Group 1 issues to be resolved with the highest priority, Working Group 2 issues to be resolved in early 2020, and Working Group 3 issues to be resolved by mid-2020. CESA will monitor this proceeding and continue to avoid taking positions on cost allocation issues. However, cost allocation is an increasingly important matter that affects energy storage procurement, especially as the state moves toward many and smaller LSEs.

As part of the Phase 2 decision, each of the IOUs established Portfolio Allocation Balancing Accounts (PABAs), which tracks all above-market fuel and non-fuel expenses and all PCIA revenues by resource vintage. Resource vintage is defined as the year in which a resource was placed in the IOU's procurement portfolio (e.g., date of contract execution, resource in-service date). Tracking actual costs and revenues by vintage was intended to ensure customer indifference such that departing load customers are only charged for what was procured up to the point of departure. PABA costs include above-market generator costs for contracts longer than one year and utility-owned generator and storage costs, but does not include above-market generator costs for contracts less than one year or costs that are recovered through a separate cost recovery mechanism.  However, REC and RA compliance market value and CAISO revenues will be subtracted out of these generator costs, which are counted in the Energy Resource Recovery Account (ERRA) for market generation and procurement variable expenses (e.g., congestion revenue rights, hedging, short-term procurement expenses. Non-resource specific sales of RECs and RA products are allocated to PABA vintages pro rata based on vintages of the pool resources. 

Benchmark True Up

On March 1, 2019 and March 26, 2019, a working group meeting was held on benchmark true-up and other benchmarking issues whereby the working group co-leads proposed that the CPUC Energy Division publish two separate RA and RPS adders by November 1 of each year. The forecast RA and RPS adders would be used in setting the PCIA rates for the delivery year while the final RA and RPS adders would be used in truing up the imputed RA/RPS PABA entries for products used by the IOUs for compliance in the delivery year. The CPUC Energy Division would count the same (single) transaction between the same parties once for purposes of calculating the adders. In particular, a Local RA adder will be used for RA sales and purchases by local area rather than by TAC areas. Open issues related to the use of backstop procurement in the RA adder and unsold RA volumes were unresolved. The CCAs and ESPs expressed some concern with the quarterly reporting requirement and the disclosure of pricing data to calculate the true-up. PAO and TURN also advocated for the inclusion of fixed-price PPAs in the RPS market price benchmark, which would otherwise skew the calculation of above-market costs, rather than using the proposed index-based benchmark.

On May 16, 2019, a workshop was held to address stakeholder concerns. The direct-access parties (AReM, Shell) opposed the quarterly reporting requirement but the facilitators responded that such reporting is needed in the short-term to ensure timely and accurate calculation of RA and RPS adders. However, there continued to be a difference in the valuation of unsold RA and RPS products, where the IOUs continued to advocate for valuing it at zero to avoid cost-shifting to bundled customers (i.e., unsold capacity is either excess or has attributes with no value) while CalCCA believed that it should be valued at some “floor price” if any (i.e., minimum value that the the IOU places on selling RA). CalCCA and the direct-access parties also favored valuing RECs at the time they are generated or at the MPB. Finally, CalCCA criticized the IOUs' proposal to not establish clear guidelines on determining when RA can be deemed "unsold" and the exclusion of CPM costs in the Local RA adder. 

On May 21, 2019, TURN submitted an alternate proposal for incorporating fixed-price bundled renewable energy transactions into the Market Price Benchmark analysis, especially given their concerns of the reasonableness of the “BP+REC” approach.

On October 17, 2019, D.19-10-001 was issued that adopted revised inputs to the market price benchmark (MPB) used to calculate the PCIA.

On January 21, 2019, an Order was issued that denied the applications for rehearing (AFRs) of D.18-10-019 filed by various CCAs, ESPs, and other groups, such as CLECA and POC. Shell disputed the CPUC’s statutory authority to compel ESPs to disclose prices for the MPB. CalCCA contended that utility-owned generation costs should not be included in the PCIA for CCA departing load customers. The Order modified the decision for some minor corrections. In particular, the Order explained that the decision reasoned how a ten-year limitation on post-2002 UOG eligibility for the PCIA could result in CCA customers being exempt from paying for a power plant built for their own reliability needs.

Portfolio Optimization & Cost Reduction

On April 29, 2019, a working group meeting was held on the structures, processes, and rules governing portfolio optimization that the CPUC should consider in order to address excess resources in utility portfolios that would be compatible under existing regulatory requirements. CalCCA proposed a sales approach, the IOUs proposed an allocation approach, and others proposed ‘sell-all then buy-all’ approach for RA and RPS attributes of resources in excess of what is required for IOUs. Under any approach, sufficient time is needed for LSEs to meet their monthly and annual RA obligations (e.g., sales could occur bi-annually or quarterly) and annual RPS obligations (e.g., semi-annual sales). There are questions to how much ‘buffer’ the IOUs should be allowed with their excess RA and RPS attributes to meet their Local RA and RPS compliance requirements and whether excess RA capacity and RPS energy should be subject to a floor or ceiling price.

On July 25, 2019, a working group meeting was held on where a structure for the sale of excess System and Flexible RA was presented. The co-leads of the working group (SCE, CalCCA, Commercial Energy) offered a proposal that allocates Local RA and GHG-free attributes to LSEs based on the PCIA costs paid by each type of LSE. Commercial Energy also presented its Voluntary Allocation and Auction Clearinghouse (VAAC) proposal to allow all LSEs that pay PCIA charges to buy attributes from PCIA-eligible resources. However, the co-leads of the working group could not agree on how to calculate the RA buffer and what constitutes “excess” in light of the IOU’s practice of retaining capacity to account for forecast uncertainty, even as all agreed that there are uncertainties (e.g., load migration, growth, and decline, operational constraints, planned/forced outages, regulatory rule changes, delays in deliverability) associated with RA sales. Furthermore, the co-leads could not agree on how RA not offered in solicitations or RA not shown in supply plans due to foreseen operational constraints and outages should be valued in calculating the PCIA. However, certain parties such as PAO expressed concerns that the multiple types of “cushions” are becoming redundant and duplicative.

On December 11, 2019, a workshop was held, where among other things, an RFI contract reassignment proposal was presented  where IOUs could connect interested sellers with LSEs or other market participants who are interested in taking assignment of contracts from the IOU portfolio, or could propose contract buy-outs. The process will be held annually for the first two years, after which the CPUC would consider whether the process should be modified or continued.

On February 21, 2020, a Working Group 3 Final Report on portfolio optimization issues was prepared by CalCCA, SCE, and Commercial Energy that recommended changes to the PCIA methodology, including the option for CCAs to take allocations of resources (RA and RPS products, GHG-free energy) from the IOU portfolio that the CCA customers are already paying for. This is in contrast to the status quo where CCAs pay the existing PCIA and have to separately procure their own resources. The following key proposals were included.

• Voluntary Allocation & Market Offer (VAMO) Proposal, a consensus proposal supported by the three co-chairs, requires the allocation and/or sale of the IOU PCIA-eligible portfolio (i.e., System/Flexible RA, RPS, GHG-free energy) on an annual basis based on LSE load share. Unlike previous proposals, the VAMO proposal would bypass issues around determining “buffers” or “uncertainty” around IOU positions. Each LSE can opt into annual, forward allocations of 10 or more years of the attributes of IOU RPS resources if it pays the market value of the associated RPS resources, and has a one-time opportunity to be grandfathered into the IOUs’ underlying long-term contract treatment if it assumes RPS allocations for the remainder of the duration (at least 10 years from the allocation start date) of its customers’ vintage portfolios. Declined allocations will be offered for sale by the IOUs through a market offer process. Implementation is proposed to commence in 2022 for the 2023 compliance year and deliveries.

• Local RA Allocation Proposal, a non-consensus proposal supported by SCE and CalCCA, would allocate IOUs’ PCIA-eligible Local RA portfolio to all LSEs on a vintage forecasted coincident peak load basis without an option to decline the allocation and without a market offer. Whereas the CAM is not vintage-specific, the allocation will be for vintaged PCIA-eligible resources in order to ensure a fair distribution based on cost responsibilities and account for the multi-year forward showing requirements. Implementation is proposed to commence in 2022 for the 2024 and 2025 compliance years. However, this proposal was non-consensus because other working group participants (i.e., ESPs) contended that this allocation should be voluntary to support procurement autonomy.

In light of the above, the report details a recommendation to direct the IOUs to issue a Request for Interest (RFI) in 2021 and 2022 to solicit interest from their RPS counterparties in pursuing buy-outs or full assignments to other LSEs that would remove the IOU’s RPS contracts from the IOU’s portfolio. The IOUs would then be directed to report on outcomes of the new RFI processes, including identifying all rejected offers and the basis for not moving forward in negotiations or being unable to reach an agreement. Following the issuance of the working group, several new proposals were submitted during the comment period:

• Hybrid Allocation Framework, an alternative proposed by SDG&E, requires the IOUs to determine their excess procurement by forecasting their RA needs, with buffer and uncertainty tranches set at 0% just as in the VAMO Proposal. SDG&E said that this allows the IOUs to make available the greatest amount of excess resources to the broader market, while still permitting the IOUs to meet their own compliance obligations and avoiding a circumstance where an IOU has to repurchase attributes it was forced to allocate out. If any excess remains unsold when final obligations are provided by the CPUC, then the IOUs would allocate the remainder unsold excess products to all LSEs, including bundled customers, on a peak load ratio basis.

• Attribute Distribution Framework (ADF), as proposed by PG&E, would allocate PCIA-eligible Local RA resources on a mandatory basis using CAM, allow a one-time option for LSEs to elect to receive long-term RPS allocations, and allocate GHG-free energy as long as LSEs also take their share of the GHG emissions of the IOU’s portfolio. All other resources would be sold on an excess basis.

• Shareholder Responsibility Disallowance Proposal, as proposed by CalCCA, would subject an IOU to potential cost recovery disallowance for not accepting or otherwise pursuing an offer from a counterparty in the RFI to modify or terminate an existing, CPUC-approved contract.

In comments, the co-chairs and PAO aligned in support of the consensus proposals while PG&E, SDG&E, and AReM (representing energy service providers at large) were largely aligned against the proposals and in favor of their more incremental alternatives. In particular, they raised issues with the consensus proposals as not narrowly focusing on “excess resources” and not addressing how IOUs may need to re-balance their portfolios after allocations. Notably, AReM highlighted the complexities of creating a “secondary market” for PCIA showings and allocations that may allow CCAs to offset each other’s position but would disadvantage ESPs that cannot leverage each other. Similarly, SDG&E explained that the CCAs could bypass MCC limitations. SCE and CalCCA, meanwhile, opposed the PG&E and SDG&E alternative proposals as not advancing portfolio optimization and for leading to potential surprise allocations and costs when “excess” is defined by the IOU. Finally, TURN and PAO expressed concern that short-term RPS contract allocations could count toward an LSE’s long-term contracting requirements.

This report on portfolio optimization proposals was intended to help reduce PCIA charges and rebalance each LSE’s positions, particularly the “long” positions of the IOUs on their RA and RPS obligations as their load share departs to CCAs. This proposal would likely impact a number of legacy RPS contracts and thus not impact too many storage contracts. Most storage projects are under RA contracts, where the report recommends mandatory allocations involving no contract reassignments or changes, in contrast to RPS contracts that could be subject to voluntary allocations, buy-outs, and modifications for other LSEs. However, there was some uncertainty around how this PCIA proposal aligns and interacts with the CPUC’s central buyer proposed decision. Furthermore, the report assured that any contract assignment, modification, or termination would require the agreement with the contracting party. If only involving allocations (not sales of contracts), then the report explained that contractual obligations will be maintained (e.g., scheduling coordinator, off-taker). The only concern was around the recommendation that the outcomes of the RFI process could lead to the release of confidential information, which, in comments, developer groups opposed, and SCE concurred as not being the intent.

Prepayment

On April 4, 2019, a workshop held that focused on the criteria for evaluating and approving prepayments and the time period over which the prepayment can be made. The spectrum of approaches was discussed. On one end, the CPUC could adopt a prescriptive process whereby regulators would set the prepayment conditions, but on the other end, a more bilateral negotiation approach could be allowed. An initial straw proposal was shared by the working group co-chairs, whereby the PCIA prepayment price could be determined by some “starting point” methodology, adjusted or modified based on independent modeling and analysis conducted by negotiating parties, and then have a final prepayment price negotiated and mutually agreed to by the parties. The PCIA prepayment load volume used to calculate the prepayment amount would be the three-year historical average customer load, and the PCIA prepayment amount would equal the present value of the customer’s forecasted PCIA obligation based on a customer vintage. A key difference in the proposal was that SDG&E suggested a “statutory indifference exit fee” to ensure customer indifference when a single party requests a prepayment arrangement, while AReM and DACC disagreed with the need for such a fee. In addition, the co-chairs suggested four guiding principles for negotiating the prepayment price. These include risks related to market forecast, volumetric sales, regulation, and credit/finances. These principles would thus establish a forward-looking option for LSEs over a specific period of time, which could be paid all upfront or levelized over time. Whether a partial prepayment option will be considered and whether prepayment agreements can be re-opened due to statutory and/or regulatory changes are still up for debate.

On May 31, 2019, a workshop was held on prepayments. SDG&E proposed a Non-Pre-payer Protection Reserve (NPPR) as a refundable, upfront, negotiated, escrow-like payment that would be used to recover under-collections due to prepayment arrangement, thus addressing material or unanticipated load increases. The framework would also include “shadow bills” for what would have been paid through PCIA if not prepaid. Both PG&E and SCE supported the true-up proposal as guarding against cost shifts from load forecasts that will inevitably go wrong. The ratepayer advocates (PAO, TURN) also supported such true-up concepts but supported variations of SDG&E’s proposal to avoid cost shifts where prepayments could be subject to “risk premium payments” (PAO) or only be subject to true-up if load forecast deviations are material. CalCCA, however, opposed SDG&E’s proposal as discouraging prepayments and forcing true-ups on load forecast uncertainty that affects future procurement decisions, not past procurement decisions, which is the subject of the PCIA.

On November 4, 2019, a workshop was held where CalCCA supported prepayments, with flexibility in the number of years and amount of load, as a valuable method to protect customers from rate shocks and support a stable market. SCE, however, opposed partial pre-payments because it would invite gaming to opt back into PCIA if PCIA prices go down and would require serial negotiations, though SCE supported the concept of only allowing partial pre-payments if both counterparties agree to it. PG&E expressed similar concerns with many CCAs or ESPs seeking pre-payment, leading it to propose additional processes (CPUC application for approval, refundable deposit) to determine serious interest and commitment. PG&E also proposed a lottery to only process up to 6 prepayment applications per year to manage the administrative burden.

On December 9, 2019, a Working Group 2 Report was submitted that laid out the market forecast principles, set the three-year historical average load as a starting point for assessing volumetric risks, and established bilateral contract negotiations as the forum to handle regulatory risk. However, there were several different proposals and comments by parties representing non-consensus items on this issue. CalCCA commented on the need to ensure transparent, binding, consistent, and unbiased calculation and payment of prepayment amounts and recommended that load growth for CCA customers should not be subject to additional PCIA charges since the IOUs are no longer serving that load. UCAN echoed concerns that the IOUs may require unduly high-risk premiums. The IOUs and CUE, by contrast, similarly argued that quantifying customers’ future PCIA obligations up to 20 years into the future can be challenging, leading to risks of cost shifts, and disagreed on the use of partial prepayments.

The IOUs generally got behind SDG&E’s NPPR concept – a one-time, refundable escrow-like payment that operates to minimize the risk of cost-shift. The NPPR involves a contractual PCIA prepayment amount that is comprised of: (1) a negotiated, non-refundable “base” prepayment amount representing a conservative estimate of the net present value (NPV) of the PCIA obligation using high-probability assumptions; and (2) the negotiated, refundable NPPR, which is incremental to the base amount and reflects an estimate of the prepayer’s potential additional PCIA obligation that takes into account market and volumetric uncertainty. The prepayer and IOU would mutually agree on the level of the base amount.

TURN also included a “circuit breaker” proposal in the report whereby risk is mitigated by treating non-prepaying customers and prepaying customers symmetrically. Prepayment contracts would require parties to renegotiate the contract’s terms if PCIA rates deviate by a certain percentage. The IOUs, however, opposed TURN’s proposal because prepayers should not get a “take back” if market conditions did not go their way. CUE also submitted a proposal using a bank-financing approach.

On August 12, 2020, D.20-08-004 was issued that adopted the working group consensus framework for negotiation of prepayment agreements of the PCIA obligation for departing load customers and establishes the guiding principles for prepayment arrangements (i.e., market forecast risk, volumetric risk, regulatory risk and credit, commercial and administrative procedures). The PCIA prepayment amount will be equal to the present value of the customer’s forecasted PCIA obligation based on customer vintage for the contractually-identified DA meter(s) or CCA customer load. To establish a mutually acceptable forecast of the customer’s future PCIA obligation, a starting point is established based on publicly-available data provided by the IOU. Once the starting point is established, each negotiating party will then conduct independent modeling and analysis to further develop its proposed prepayment price, each considering its own proprietary assumptions regarding forward pricing and risk. The IOUs are directed to file Tier 2 Advice Letters within 60 days detailing administration of the prepayment requests and negotiations, including justifications for the limitations on the number of requests.

However, contrary to CalCCA’s recommendations, partial payments are not allowed since the decision cited D.18-10-019 that only allowed one-time transactions to provide cost certainty to departing load customers. Notably, the decision rejected TURN’s circuit-breaker proposal that would have changed cost responsibilities of prepayers unless specific variables deviate by a larger than agreed-upon percentage from the assumptions used to calculate the initial prepayment. The decision found this proposal to be a true-up mechanism that previous decisions rejected.

In response to the PD, the IOUs were generally supportive but sought clarifications to utilize existing dispute resolution processes for unsuccessful bilateral negotiations where parties acted in bad faith and to have non-IOU LSEs pay for the transaction costs of engaging in prepayment negotiations, even if unsuccessful. CalCCA was partially supportive and recommended that the PD be improved by capturing the reduced labor costs (e.g., RPS procurement) from load certainty and by removing the viability screening criteria set by the IOUs, such as requiring 10 years of PCIA obligations as collateral or requiring investment-grade credit from the counterparty. Additionally, CalCCA made another appeal to partial prepayments as it would help mitigate forecast risk and not force LSEs to finance 100% of their PCIA obligations. TURN, however, rebutted arguments made to reject its proposal, arguing that the PD’s approach would not mitigate “load gaming” tied to historic usage despite an intention to increase their load share in future years. Similarly, PAO expressed concerns with the lack of risk mitigation mechanism in cases where inaccurate prepayment calculations are made. In response, the decision was revised to clarify that the prepayer is responsible for application and negotiation costs, even if the process does not result in prepayment and that the CPUC ALJ Division has a dispute resolution department to arbitrate inter-LSE negotiations.

This decision does not impact energy storage procurement, but it provides a means for non-IOU LSEs to “buy out” their PCIA obligations, thus providing greater certainty about their procurement costs, whether bundled by IOUs or unbundled by non-IOU LSEs. Greater cost certainty will support CCA and ESP procurement of resources, with less fear of additional sunk costs being added due to load migration.

Load Forecasting & Billing Determinants

On June 7, 2019, a workshop was held on load forecasts and billing determinants. The IOUs continued to push for binding estimates on a one-year forward basis while supporting the development of a proposal for a three-year forward estimate that could be used for multi-year RA purposes. CalCCA opposed such mandatory binding estimates and instead sought to investigate the assumptions that go into the IOUs’ load forecasts. The direct-access parties (AReM, DACC), meanwhile, argued that existing processes are sufficient (e.g., RA month-ahead load forecast modification) and that the IOUs can assume direct-access load will not change based on the number of customers under the direct-access cap.

On July 9, 2019, a Ruling that set the schedule for responding to the Working Group 1 Report on Issues 8-12. The following consensus proposals were included in the report for Issue 8 around forecasting departing load, Issue 9 around obtaining the information to adequately forecast future CCA departing load, and Issue 10 around minimizing future deviations between announced and actual load departure dates:

• A probability-based model is best suited for mid-to long-term planning where there is considerable uncertainty about the load that will be served by LSEs; this approach can be supplemented with scenarios by altering the probabilistic model variables to reflect different assumptions about the future.

• A deterministic forecast method is appropriate where there is greater certainty based on binding commitments to serve load by LSEs (e.g., Resolution E-4907 filings, binding notice of intent), such as the year-ahead forecast. In such cases, IOUs could include in their departing load forecast the load of CCAs and ESPs that have filed either a BNI or implementation plan, less customers projected to opt out.

• The CPUC and CEC should consider adopting a probabilistic forecasting approach that reflects prospective departing load in its forecast.

• The general forecasting approach should align across entities, but details may vary given the unique circumstances related to departing load in each territory.

• With respect to year ahead forecasting, the CPUC should adopt a Resolution E-4907-type requirement for DA Customers in accordance with D.19-05-043.

• With respect to mid-term 2-3 years forecasting, the IOUs should continue to refine estimation of probability of formation given state of CCA activity for a given community.

• With respect to the long-term (4-10 years) forecasting timeframe, the CPUC should recommend the CEC adopt a probabilistic approach supplemented with scenarios and account for prospective departing load.

• With respect to the long-term forecasting timeframe, the CPUC should require increased coordination between IOUs, CalCCA and CEC regarding identification of key drivers of load departure and the IOUs should continue to evaluate and update proposed methods/inputs.

• To the extent practicable, LSEs should use standardized load data sets and assumptions when applicable.

However, the CCAs expressed concerns with a probabilistic departing load forecast methodology supplemented with a scenario-based approach. Both the IOUs and CCAs agreed on the need for a working group process to discuss departing load forecast matters, with the IOUs supporting but the CCAs opposing a binding notice of intent process for a three-year forward period. The CCAs argued that it is virtually impossible to bring certainty to departing load forecasts. Furthermore, while the IOUs recommended that the CPUC require a mechanism that increases certainty in year-ahead, mid-term, and long-term forecasts from ESPs and CCAs, including a binding notification of departure, CalCCA opposed imposition of an involuntary, binding, schedule for departures on departing load.

Consensus was not reached on proposals in the report for Issue 10 and 11 around clarifying the definition of and specifying the aspects of billing determinants. The IOUs recommended the use of vintage bill determinants instead of total system sales to calculate forecast PCIA rates to prevent under-collections from the PCIA and that the standard PCIA template be corrected to eliminate the application of line losses to the PCIA amount calculation (which the CCAs opposed).

Finally, there was no consensus on proposals for Issue 12, which considered changes to the presentation of the PCIA in tariffs and on customer bills, due to time constraints. The IOUs indicated that it will be able to show the PCIA as a separate line item on customer bills starting in 2021 in line with their billing system upgrade timeline. Finally, the IOUs introduced the topic of applying the line loss factor in the PCIA template, which creates errors in the indifference amounts used to set the PCIA. The CCAs opposed the proposal to eliminate line loss factors at this time due to further discussion being needed, other than to eliminate the calculation error.

On April 6, 2020, D.20-03-019 was issued that declined to adopt any technical modifications to departing load forecasting (Working Group 1 Issues 8-10) and directed the IOUs to collaborate with the CCAs to submit a joint proposal for bill and tariff changes to show a PCIA line item in their tariffs and bill summary table on all customer bills (Working Group 1 Issue 12). Additionally, the PD denied the Joint IOU proposal to remove the line loss factor from the calculations underlying the PCIA since this requires more review; the correct action would be for the IOUs to submit a PFM. In declining any modifications to departing load forecasting, the CPUC found that the Demand Forecasting Subgroup at the CEC as being the appropriate forum and did not find any of the proposed approaches as improving current forecasting practices, especially considering load departure can often be a political decision by local governments. Instead, the CPUC directed more coordination and information sharing between the IOU and CCAs in their service territory (e.g., meet-and-confer requirements). Altogether, the bill and tariff changes must be made by 2021.

On August 31, 2020, the IOUs submitted a joint advice letter that proposed to refine the definition of the PCIA to clarify that all customers pay the PCIA and add a PCIA line item to bundled customer bills. This proposal is relatively straightforward and intended to improve customer understanding of the competitive rates for different LSE options, with the PCIA charge itemized and clarified on customer bills. CalCCA and DACC submitted a joint response in support.

Resource Adequacy

Background

The CPUC’s Resource Adequacy (RA) program requires load-serving entities (LSEs) to enter into contracts with suppliers to satisfy their monthly and annual RA obligations. RA is determined in an annual rulemaking proceeding that uses generation capacity needs determined in the Long-Term Procurement Planning (LTPP) proceeding to order LSEs to meet their allocated RA and reserve capacity requirements. 

In 2004, D.04-01-050 adopted an LSE-based RA program where each LSE is responsible for acquiring the resources needed to meet its own monthly forecasted load plus a Planning Reserve Margin (PRM) of 15%. The program began implementation in 2006 and continues to provide the energy market with sufficient forward capacity to meet peak demand. This capacity includes System RA and Local RA (measured in MWs). The annual and monthly requirements for CPUC-jurisdictional LSEs are set by the CPUC. LSEs are defined by Section 380(j) as "an electric corporation, electric service provider, or community choice aggregator."

In 2013, D.13-06-024 adopted an interim flexible capacity requirement as an additional component of RA requirements. 

In 2014, D.14-06-050 adopted an interim flexible capacity framework for the 2015-2017 RA years.

2016 RA Resource Mix

Source: CPUC

Local Capacity Requirements (LCR) Study Findings

LCR studies use a methodology that maximizes import capability into the local area, maintains path flows, maintains deliverability for deliverable units, defines load pockets, and utilizes performance levels B & C. The purpose of sub-area LCR needs is to provide detailed local procurement information, satisfy the CAISO's minimum back-stop, and demonstrate that the sum of the parts may not equal the overall need. 

On March 9, 2017, the CAISO held a stakeholder meeting to summarize the 2018-2022 Draft LCR study results. The results showed that total 2018 LCR needs have increased by 550 MW (2.2%) and that 2022 LCR needs have increased by 1,372 MW (11.6%). Due to a decrease in load forecast and expected transmission projects, the 2018 LCR needs for North Coast, North Bay, Kern, Bay Area, and LA Basin have reduced 2018 LCR needs. On the other hand, the 2018 LCR needs have increased in: Humboldt due to different limiting contingency; Sierra, Stockton, Fresno, Big Creek, and Ventura due to load forecast increase; and San Diego due to inconsistent resource assumptions during the 2017 study.

On June 25, 2018, D.18-06-030 was issued that adopted the local capacity requirements (LCR) for 2019 but deferred adoption of flexible capacity requirements (FCR) for 2019 to a separate decision because of the further study required by the CAISO. Overall, LCR needs have increased by 37 MW from 2018 to 2019, specifically in North Coast-North Bay, LA Basin, Big Creek-Ventura, Sierra, and Kern due to load increases, resource distribution, and limiting elements. The LCR needs decreased in Humboldt, Fresno, Bay Area, and San Diego due to load decreases and approved transmission projects. In comments to the draft study results, Wellhead discussed how the CAISO’s assumption for forecasting error being zero is insufficient based on past FCR assessments of predicted and actual and instead the Fast Flex RA product (with certain attributes) should be equal to the forecasting error. Wellhead pointed out that FCR needs may be concentrated in one hour, not evenly distributed across all three hours. Cogentrix and SDG&E focused their comments on the overrepresentation of available capacity in the San Diego-Imperial Valley area and on concerns around not separately examining the San Diego-Imperial Valley and LA Basin areas, leading to concerns about properly allocating LCRs when SDG&E has found the two areas having diverging area peaks and load shapes. PG&E, meanwhile, commented on how the study may overlook the need for flexible resources because of how renewable generation is contracted with LSEs and place bids into markets to curtail output. The CAISO responded to SDG&E’s comment, saying that separate studies for the two areas cannot be conducted due to the interconnected nature of SDG&E’s transmission system that benefits from the support of other systems under critical contingency events.

Flexible Capacity Requirements (FCR) Study Findings

FCR studies calculate the requirements for all Local Regulatory Authorities (LRAs) within the CAISO footprint for future RA compliance years. Each Load Serving Entity (LSE) is required to make a year-ahead and month-ahead showing of flexible capacity for each month of the compliance year. In the year-ahead, LSEs need to secure a minimum of 90% of the next year's monthly needs. In the month-ahead, LSEs need to secure adequate net qualified capacity to serve their peak load including a planning reserve margin and flexible capacity to address the largest three-hour net load ramps, plus contingency reserves. All resources participating in the CAISO markets under an RA contract will have a must-offer obligation and must submit economic bids in the real-time market consistent with the category of flexible capacity.

On April 6, 2017, the CAISO held a stakeholder call to summarize its 2018 Draft FCR study results, which showed that flexible capacity needs are largely attributable to the change in output from solar resources and occur mostly for CPUC-jurisdictional LSEs. Flexible capacity need is largest in the off-peak months, which is attributable to the three-hour ramp rather than an increase in peak load. Compared to last year's forecast, flexible capacity needs are high in many months. It is important to note that the CAISO changed the must-offer hours for peak and super-peak resources from 12-5pm to 3-8pm for May-September, and from 3-8pm to 2-7pm for January-April and October-December.

On May 1, 2018, the CAISO released its 2018-2022 Final Flexible Capacity Requirements (FCR) Study Assessment. Related to the subject of the FRACMOO work, the CAISO observed in these final studies that approximately one-third of the 2016 Flexible RA showing were the slow-start, slow-ramp once-through-cooling plants that are set to retire in the coming years. In addition, a key change in the 2018 study as compared to the 2017 study was that the CAISO changed the Peak and Super-Peak Flex RA must-offer obligation hours – i.e., 3-8 pm for May-September and 2-7pm for January-April and October-December.

On June 26, 2018, D.18-06-031 was issued that adopted the 2019 FCR Report. The CPUC expressed misgivings about the CAISO delaying the process to conduct further study, which shortened the review and comment period for stakeholders. Notably, the 2019 FCR needs have increased for every month of the year.

Annual RA Reports

In January 2017, the annual report summarizing the RA program experience during the 2015 compliance year was published. The RA program for 2015 successfully provided sufficient resources (52,743 MW) to meet peak load (forecasted at 45,747 MW) in August 2015. Actual peak load in 2015 occurred on September 10, 2015 at 47,252 MW.The LSEs also fulfilled their local RA obligations (22,809 MW) with 22,963 MW in physical resources, cost-allocation mechanism (CAM) resources, reliability must-run (RMR) resources, and DR resources. In total, 1,005 MW of new generation came online, with the vast majority coming from solar PV, and 530 MW of generation retired. With monthly capacity prices weighted by number of MW in a contract and compared across zone, local area, month, and year, the CPUC found that the weighted average price for all capacity is $2.85/kW-month in 2015. The weighted average capacity price for capacity South of Path 26 is about 40% higher than the weighted average capacity price of North of Path 26. As expected, capacity prices are highest during the summer months of July-September and in locally constrained areas such as San Diego, LA Basin, and Big Creek-Ventura.

In June 2017, the CPUC published its annual report summarizing RA program experience for the 2016 compliance year. In 2016, the RA program successfully provided sufficient resources to meet peak load and fulfilled their local RA obligations. The weighted average price for all capacity in the dataset is $3.10 kW-month. The weighted average capacity price for capacity South of Path 26 is about 78% higher than the weighted average capacity price of North of Path 26 capacity.  As expected, capacity prices are highest during the months of July through September and in the following locally constrained areas: San Diego, LA Basin, and Big Creek-Ventura. New generation resources in 2016 (3,592 MW) were mostly renewable generators with the vast majority being solar PV. New NQC energy storage resources that came online in 2016 include Pomona (20 MW), Mira Loma A/B (20 MW), Tehachapi (8 MW), and Yerba Buena (4 MW).

Availability Limited Resources (R.17-09-020)

Track 1

On October 23, 2017, a workshop was held to discuss the issue raised by DR parties of addressing inconsistencies around the definition for dispatchability was discussed. For example, key questions that must be answered include whether “dispatchability” requires real-time market participation, and whether intermittent resources and QF resources could be classified as dispatchable resources.

On February 22-23, 2018, a workshop was held on Track 1 proposals submitted by parties. A wide range of ideas was proposed and presented at the workshop. The CAISO presented its analysis of slow-response resources for Local RA and found that there are limiting factors in some local and sub-areas due to longer daily duration hours of peak load. The CAISO thus proposed that the CPUC adopt its methodology to identify the maximum level of use-limited capacity in each local and sub-area based on the existing four-hour minimum duration that could count toward Local RA. In Track 2, the CAISO recommended developing a framework to accommodate increasing levels of use-limited resources in these areas to meet Local RA requirements.

On June 25, 2018, D.18-06-030 was issued that approved the PD with only minor clarifications and modifications. Several issues were deferred to Track 2 due to limited record development or policy development needed in other policy venues, including pre-contingency dispatch of DR resources for Local RA and a change from a 30-minute to 20-minute response time for DR resources to qualify for Local RA. 

Track 2

On July 10, 2018, opening testimony for Track 2 proposals were served by more than 20 parties. 

CESA was focused on a specific proposal included in the CAISO’s testimony. While the CAISO continues to seek RA rules whereby the fleet that is available to the CAISO can be used to reliably operate the grid in nearly all circumstances, the CAISO also sought to explore how and if to limit the reliance on ‘availability limited’ energy resources in local capacity areas and sub-areas. The CAISO fretted that local resources may be needed to operate for more than the normal four-hour RA period and thus proposes to consider a cap on energy-limited resources serving these areas. CESA sought further analysis form the CAISO on the appropriate energy duration needs for these areas as well as other information that can help us to evaluate the reasonableness of the CAISO’s concerns, and how to address such concerns.

See CESA's testimony on July 10, 2018 on Track 2 Proposals.

On August 8, 2018, CESA offered the following (more procedural) recommendations as well as some responses to testimony served by other parties. In particular, CESA commented that the CAISO’s proposed hourly load and RA analysis is reasonable but caps on availability limited resources should not be implemented to address identified grid needs. 

See CESA's comments on August 8, 2018 on the E-Mail Ruling

Track 3

On July 5, 2019, D.19-06-026 was issued that recognized the CAISO’s concerns about the ability of availability-limited resources, which have duration or event-call limitations (e.g., storage, DR), to meet certain local capacity needs (e.g., longer duration) but declined to adopt any specific or new requirements, as nothing specific was proposed by parties. The decision also discussed how the CPUC plans to work closely with the CAISO on this potential issue. In comments to the PD, PG&E and SDG&E commented on a related issue for third-party DR programs, such as the DRAM. Specifically, they recommended that the QC for DRAM resources be based on observable and verifiable event performance data such as through LIPs.

Bilateral RA Contracts

Background

On June 25, 2018, D.18-06-030 was issued that approved the PD with only minor clarifications and modifications. Specifically, the decision clarified that LSEs under the multi-year Local RA framework could also procure Flex RA attributes when procuring for multi-year Local RA. Whereas the PD set a 100% local requirement for the first two years, the decision was slightly modified to reduce the second-year requirement at 95% to reduce the risk of over-procurement. The key takeaway from this decision is that the CPUC is concerned about how load migration has been impacting (and will continue to increasingly affect) resource planning for reliability, as CCA expansion continues to grow and needed generators face retirements (with the decision even highlighting two such resources in Ellwood and Ormond Beach). Thus, the CPUC indicated that they decided to make major foundational changes to the RA framework to improve market efficiency and enhance reliability, though they have concerns of the risks of turning to a centralized capacity market due to the state’s renewable goals. However, there is still much to be determined in terms of the success of this new framework, given that the details must be developed in Track 2. Overall, the decision provided guidance on developing a multi-year Local RA framework and central buyer concepts, while kicking most all other issues to Track 2 to allow for more record development.

Ormond Beach

On February 28, 2018, NRG submitted a notice to the CPUC and CAISO that it plans to retire and shut down the Ormond Beach Generating Station by October 1, 2018 and the Ellwood Generating Station by January 1, 2019. 

On September 4, 2018, SCE filed an advice letter announcing one-year bilateral RA contracts (through November 2019) with the 54-MW Ellwood plant and 750-MW Ormond Beach plant in the Moorpark sub-area of the Big Creek/Ventura local reliability area, pursuant to the RA Track 1 Decision (D.18-06-030). SCE discussed how these RA contracts are less costly than anticipated RMR backstop procurement and are comparable to recent contract prices for the current contract prices and same/similar facilities.  SCE used the recent Metcalf ($6.04/kW-month) RMR agreements, the Feather River and Yuba City RMR agreements ($6.13/kW-month), and the CPM soft cost cap ($6.31/kW-month) as reference points.

On November 5, 2018, SCE submitted two advice letters seeking approval of two bilateral RA contracts with the 54-MW Ellwood Generating Station and the 750-MW Ormond Beach Unit 2 (Oxnard) from December 2019 to December 2020, pursuant to the RA Track 1 decision (D.18-06-030). The combustion turbine peaker (Ellwood) and once-through cooling unit (Ormond) were found to be necessary to meet local capacity requirements in the Santa Clara and Moorpark sub-areas, but instead of proceeding with a RMR designation, the CPUC directed bilateral negotiations between SCE and NRG with the hopes that it may be less costly than backstop procurement measures. SCE reported that the final contract prices for Ellwood and Ormond are comparable to their current contract prices and are less than the RMR prices for Metcalf ($6.04/kW-month), Feather River and Yuba City ($6.13/kW-month), and the CPM soft-offer cap ($6.31/kW-month). SCE added that Ormond Beach would also meet the OTC compliance requirements of the State Water Resources Control Board, which must be met by 2021.

On April 2, 2019, Resolution E-4986 was issued that approved the RA capacity contract between SCE and GenOn Energy Management (a subsidiary for NRG) for Unit 2 at Ormond Beach Generating Station in Ventura, CA. SCE entered into the contract pursuant to D.18-06-030, in which the CPUC directed SCE to attempt to secure capacity from Ormond Beach to meet anticipated local reliability needs in 2019 and 2020. The 2020 Ormond Contract has a term of December 1, 2019 through December 31, 2020, which adheres to the state’s 2021 OTC compliance deadline. By contracting for this natural gas fueled power plant, which declared its intent to retire in February 2018, the plant avoids more costly backstop procurement to meet reliability needs in the Moorpark sub-area while the CPUC considers more durable RA mechanisms.

Otay Mesa Energy Center (OMEC)

On January 22, 2019, Draft Resolution E-4981 was issued that denied SDG&E’s request for pre-approval for a new 5-year RA contract (2019-2024) for OMEC, a 605-MW gas-fired power plant that has been determined by the CAISO as being needed for local reliability in the San Diego-Imperial Valley local area, on the grounds that the benefits identified by SDG&E are modest, uncertain, and appear to materialize only if energy prices do not increase from 2017. Under the existing agreement, OMEC may exercise its Put Option by March 15, 2019 to require SDG&E to purchase and own OMEC for approximately $280 million, which is below “market” price. Since the CPUC previously found the ownership provisions to be reasonable, the Draft Resolution declined to take any action here.

In comments, the CCAs generally supported Option A to approve the proposed PPA for five years (instead of 20 years) given load migration trends, where CCAs will be in a position to address any local capacity needs five years from now with new CCA formation complete. PAO also supported Option A because the CPUC had not evaluated the net benefits of SDG&E owning the facility (Option B), where an increase in gas prices could lead to increase in the cost of OMEC ownership and since Option B could prolong the plant and lead to greater GHG emissions. PAO also highlighted the CAISO’s 2028 long-term study in the TPP where there would be 235.6 MW of surplus capacity in 2028 in San Diego-Imperial Valley local area without OMEC. However, TURN supported Option B since there are ongoing issues in other proceedings to address the matter (i.e., GRC) while POC found no need for OMEC capacity altogether given their views on the procedural history and the overestimated needs analysis from the CAISO.

On February 25, 2019, Resolution E-4981 was issued that approved Option A.

On March 27, 2019, POC filed an application for rehearing of Resolution E-4981 on procedural grounds but also by contesting the cost of capacity under the confirmation as exceeding fair market value and by highlighting the lack of need for OMEC. SDG&E and Calpine disagreed that approval of the confirmation requires a formal application and that CPUC approval of the resolution violates AB 117, among other things.

Behind-the-Meter (BTM) Export RA Capacity

Background

On June 30, 2020, D.20-06-031 was issued that directed a joint-agency workshop to address the following issues:

• Forward determination of capacity associated with renewable production, consumption, charging, and export

• RA requirements associated with customers providing capacity

• Wholesale market participation including metering, dispatch control, and communication with CAISO

• Cost for energy associated with consumption, charging, and export

• Changes such that NEM and SGIP resources are compensated for capacity, while discounting for their NEM and SGIP compensation as necessary to ensure that the resources do not receive compensation beyond their value

• Load forecasting and adjustment for BTM resources

• Interaction of such resources with existing BTM resources such as proxy DR

• Deliverability determination

This is an important opportunity to address many of the key barriers that have dogged the valuation of exporting capacity and the provision of RA through the Non-Generator Resource (NGR) model or as retail-side load shifting capacity. While these issues will likely not be addressed until Track 4 of the RA proceeding, or elsewhere, CESA views this as a key opportunity to advance the role of DERs as RA capacity, building off our work in the Multiple-Use Application (MUA) Working Group.

CESA generally agreed that each of the above issues should be discussed and addressed but noted that some of the above issues have been preliminarily or previously discussed in other proceedings or initiatives. In this proposal, the Joint DER Parties offered some preliminary responses to each of the identified issues, highlighted how otherwise stranded export capacity could have been an invaluable resource to the CAISO during the most recent heat storm, and proposed the following:

• The scope of the joint-agency workshop and follow-up activities should consider not only solar-plus-storage but also be expanded to any DER that can export energy.

• Many of the cross-cutting issues should be addressed in an umbrella proceeding focused on MUAs.

• Different pathways should be developed and supported to enable DERs to have supply-side RA value or to get load-modification credit.

See CESA’s Track 3A proposal on September 1, 2020 on the Scoping Memo

CEDMC supported the joint proposal and reminded the CPUC of the LMR DR Valuation Working Group Report, which recommended the use of “hard triggers” based on CAISO market price, load forecast, and/or day-ahead forecasted ramp and with capacity valuation using load impact protocols (LIPs). CAISO responded to load-modifying DR ideas in general support but sought to affirm the bifurcation decision where such resources would be double counted if ascribed a QC value.

Central Buyer Framework

Hybrid Procurement Model

On March 26, 2020, a Proposed Decision (PD) was issued on establishing a new Local RA “hybrid” central procurement structure, seeking to resolve the two-year-long discussion on central procurement schemes. The CPUC proposed a hybrid central procurement framework that “strikes a balance” between the residual and full procurement options while addressing the issues known for the Local RA market (i.e., equitable cost allocation, market power mitigation, self-procurement autonomy). Notably, the PD rejected the Settlement Agreement put forth by CalCCA, Calpine, IEP, MRP, NRG, SDG&E, Shell, and WPTF (the Settling Parties) to institute a residual central buyer structure on the following grounds:

• Settlement process involved procedural flaws due to insufficient opportunity to discuss new settlement agreement and to insufficient representation (i.e., only 8 parties included).

• The identity of the CPE entity was not provided.

• The Settlement Agreement does not a compromise between full and residual models.

• The Settlement Agreement would remove LSE incentive to procure via voluntary showings, leading to potential overreliance on CAISO procurement and unjust cost shifting.

• The Settlement Agreement covered out-of-scope issues such as multi-year requirements expansions without record support.

Just as with the previously-proposed full procurement model, many of the same problems are present in the currently-proposed hybrid procurement model. CESA expressed how the PD would disincentivize LSE procurement of local resources due to uncertainty related to whether the procured resources will be selected by the CPE (under the bidding option) and how much the procured resources will count toward their own share of the Local RA requirement (under the voluntary showing option).  In turn, LSEs and developers face uncertainty to the value of local resources, leading to inefficient and/or excess procurement by the LSEs and creating “leaning” issues among LSEs. CESA thus opposed the PD unless substantially modified. Specifically, CESA recommended that the collective Local RA requirements should be established after accounting for new long-term resource procurement from the IRP. CESA also recommended that the solicitation criteria should be further refined to ensure that Local RA procurement by the CPE aligns with IRP decarbonization goals while removing dispatch rights as a preferred criterion for the CPE solicitation.

Unanimous opposition to the PD was expressed by companies and trade associations representing resource developers/providers, independent power producers, and non-IOU LSEs (i.e., CCAs, ESPs) due to the PD removing the incentive for procuring local preferred resources and the uncertainty created for existing and under-negotiation resources under the proposed hybrid model. Many opponents to the PD also expressed how the CPE criteria lacked clarity or accounting of all the various factors to ensure new resource development, mitigate unintended impacts of including dispatch rights as an optional bid parameter, and a competitive level playing field. CalCCA, Settlement Parties, and AWEA-CA, meanwhile, insisted on either retaining the existing bilateral RA structure or adopting the residual procurement model given that there was limited opposition to the settlement agreement.

Several parties were in support of the PD, including SCE, PG&E, and the ratepayer and consumer groups (e.g., PAO, CLECA). The supporting parties generally did not offer any specific comments other than to request certain clarifications, though SCE emphasized that the IRP, not the RA Program, should incentivize the deployment of resources needed for long-term reliability. While preferring the residual procurement model, SDG&E narrowly supported the determination that the Local RA-only central procurement framework should not be adopted in SDG&E’s TAC area at this time, expressing how it does not want to play a CPE role when it is not projected to serve much load going forward.

Monterey Bay Community Power (MBCP) was the only party who submitted a more detailed counterproposal to the one included in the PD, whereby the CPUC would implement a full procurement model. In this alternative proposal, the IOUs would be temporarily installed as the CPE through 2025 to procure the full amount of Local RA through a single price clearing auction in each local area. Should the initial auction fail to procure sufficient Local RA, the CPE will, after giving LSEs an opportunity to procure necessary resources, issue an RFP for resources (including potentially attributes other than Local RA and for longer contract terms) to meet the remaining Local RA requirements. In the long term, the CPUC should continue examining and make recommendations by 2025 for full regional RA procurement, potentially an independently managed central capacity market covering all RA needs for entire CAISO grid.

CESA observed that many parties highlighted the flaws of the “hybrid” procurement model as proposed in the PD for its lack of clarity on a number of issues, which point to a need to make major refinements and modifications to the PD’s proposed hybrid procurement model prior to adoption and implementation by the 2023 RA compliance year. Given the multitude of issues that need to be worked through, CESA suggested that there may be sufficient grounds to delay implementation of the central procurement structure by one year and/or to consider whether a more appropriate middle-ground solution can be reached between the PD’s hybrid procurement model and the Joint Settlement Agreement’s residual procurement model, which create broader consensus of parties. Specifically, CESA also commented that a one-for-one crediting system should be maintained for LSEs that opt to show bilaterally procured resources, dispatch rights should be removed as a bid parameter, and the CPUC should defer extension of the multi-year requirements to other RA products at this time.

See CESA’s comments on April 15, 2020 and reply comments on April 20, 2020 on the Proposed Decision

On June 17, 2020, D.20-06-002 was issued that adopted implementation details for the central procurement of multi-year Local RA procurement to begin for the 2023 compliance year in the PG&E and SCE distribution service areas. The decision established the following characteristics for the hybrid central procurement structure: 

• Central Procurement Entities (CPEs): Given the potential federal jurisdiction issues of a centralized capacity market and the time it would take to establish a separate entity, the CPUC determined that the distribution utilities are the central procurement entity candidates with the resources, knowledge, and experience to procure Local RA resources on behalf of all LSEs in the near term. Nevertheless, the CPUC noted that SDG&E’s TAC area is unique in that the local RA requirements typically meet or exceed the system requirements, such that LSEs would have little procurement autonomy for System and Flexible RA under a hybrid model. Hence, SCE and PG&E were appointed the CPEs of their respective TAC areas.

• Procurement mechanism: The CPUC adopted an RFO process because it gives the CPE the flexibility to select resources based on multiple targeted criteria (e.g., costs, local needs, broader environmental goals). The CPE is permitted to conduct multiple solicitations per year, as needed.

• Resource showings: In lieu of LSE-specific Local RA obligations, LSEs may bid self-procured Local RA into the CPE RFO, where the resource would count on a 1-for-1 basis to reduce collective Local RA requirements by TAC area, if selected in the RFO. Alternatively, LSEs could voluntarily show self-procured resources for System and Flexible RA, with these resources potentially counting toward overall Local RA requirements but with no guarantees that they would count for Local RA on a 1-for-1 basis. Finally, an LSE could only show the resource for System and Flexible needs but not for Local RA needs. An LCR reduction compensation mechanism will be developed to support local preferred resources.

• Cost allocation: The cost allocation mechanism (CAM) should be used for cost allocation for any CPE procurement, moving RA costs from generation rates to distribution rates. Costs will be allocated on an ex post basis based on an LSE’s peak load share for any resources procured by the CPE.

• Evaluation of bids: The CPE should evaluate resources using the least cost best fit methodology and including the following criteria: (1) future needs in local and sub-local areas; (2) local effectiveness factors; (3) resource costs; (4) operational characteristics of the resources; (5) location of the facility; (6) costs of potential alternatives; and (7) GHG adders. The criteria included citations to the loading order and prioritization of preferred resources over fossil generation but also referenced consideration of energy limitations. Despite insufficient record to require CPE to acquire dispatch rights, dispatch rights can be included as an optional term that is encouraged. The decision also required distribution utilities serving as the CPE to bid its own resources into the solicitation at their levelized fixed costs.

• Oversight on CPE procurement: The Procurement Review Group (PRG) assumes the role to monitor and oversee the CPE through the RFO process, in consultation with Energy Division and an independent evaluator (IE). A portfolio approval process should govern when a procurement action by the CPE is deemed reasonable and pre-approved. Finally, the CPE should have discretion to defer procurement of a local resource to CAISO’s backstop mechanisms without penalties if bid costs are deemed unreasonably high, so long as the CPE made reasonable efforts to secure capacity.

• Transition to the centralized structure: For 2020, the 50% local requirement is eliminated for the 2023 compliance year; however, the 100% two-year requirement will remain such that LSEs will be responsible for 100% of their 2021 and 2022 local requirements in 2020, and 100% of their 2022 local requirements in 2021. Therefore, the CPE will begin local procurement responsibilities in 2021 for the 2023 and 2024 compliance years. The multi-year requirements are otherwise maintained in following years: 100% in Year 1, 100% in Year 2, and 50% in Year 3. Treatment of existing Local RA contracts will be handled at a later stage in the RA proceeding.

Relative to the PD, the decision was revised that declined to adopt a one-for-one credit for not accounting for a resource's effectiveness at reducing LCR needs and instead adopted an “LCR reduction compensation mechanism” to be determined in a working group process by September 1, 2020 that compensates LSEs for shown local preferred resources that provide ratepayer value and reflect the additional costs of procuring resources close to load. After accounting for local effectiveness and use limitations, the working group will need to determine the local premium’s granularity and year-to-year changes, among other things. The CPUC discussed how giving local resources inflated local capacity prices would not resolve market power issues. The decision also added consideration of how the "orderly retirement" of gas could be considered within or outside of the adopted CPE structure. The treatment of existing Local RA contracts was still to be determined in the working group process, noting that they are not inclined to grandfather resources that are not currently online. Other than some added details related to the process and options to show or bid Local RA resources, the decision was otherwise unchanged.

Overall, the final decision did not represent the wholesale change we sought given the significant opposition to the PD for the lack of clarity and incentives for new resource procurement. Rather, an unclear and to-be-determined cost-based “local premium” will be developed in future RA Working Groups in the CPUC proceeding R.19-11-009 for local energy storage and preferred resources to not “discourage” such development. However, it was entirely unclear on what is within the scope of this local premium or adder. Other than this “silver lining”, the decision has the potential to create uncertainty related to the Local RA value of existing and new storage resources. The two rounds of revisions, however, suggest that the CPUC was acutely aware of coordination and alignment of IRP long-term planning and procurement with the RA Program, particularly as it relates to gas retirements and preferred resource procurement. Additionally, the decision created uncertainty of how existing tolling agreements would be addressed with the inclusion of dispatch rights as an encouraged term. Whether the multi-year forward obligations should be extended to System/Flexible RA was deferred at this time, thus maintaining the current one-year-ahead requirement.

On July 17, 2020, WPTF filed an Application for Rehearing (AFR) that disputed the CPE decision (D.20-06-002) on the grounds that the and because the adopted framework would discourage LSE procurement of local resources, including due to the fact that the crediting mechanism would only favor preferred resources, and would be inconsistent with the statutory requirements to maximize the procurement autonomy of CCAs and minimize the need for CAISO backstop procurement. By contrast, WPTF offered the settlement agreement as a viable alternative in line with policy guidance. WPTF added that the hybrid procurement model is essentially a sale-for-resale procurement construct that could place it under FERC’s jurisdiction as a wholesale, rather than a retail, transactional framework. Interestingly, WPTF positions the CPE decision as disadvantaging gas resources due to the crediting mechanism and the negative PR from procuring gas resources. Shell echoed many of the same arguments of WPTF in its response in support. On the other hand, PG&E and SCE called for the dismissal of the AFR since many of the issues were already litigated, including the CPUC’s authority to require procurement of preferred resources pursuant to state clean energy policies. They added that the CPE scope is limited to intrastate commerce with Local RA.

On September 1, 2020, the IOUs submitted their Competitive Neutrality Proposal. PG&E and SCE pointed to Electric Rule 24 adopted in D.13-12-029 as guidance to implement a firewall between IOU personnel (i.e., physical and electronic separation) working on the CPE solicitation process and their own RA procurement activities on behalf of its bundled-service customers. SCE added that they will erect timing walls that prevent the CPE from engaging in central solicitation at the same time SCE is soliciting and procuring RA for its bundled customers, which will mitigate the risk of confidential information being shared. While the teams are separate, PG&E and SCE will provide shared administrative services (e.g., accounting, legal, compliance) but have these individuals “avoid being conduits” for the passage of information between the teams and only have access to confidential materials on a “need-to-know” basis. Strict code of conduct and associated training will be developed in collaboration with Energy Division, independent evaluator (IE), and procurement review group (PRG). Executives will also be subject to all of these requirements. Notably, SCE proposed that the competitive neutrality rule do not apply to new generation solicitations, where all its resources available are needed to evaluate bids in a solicitation. SCE argued that this does not pose a competitive disadvantage to non-IOU LSEs since there is no “history of information” on other prices that could be used to take advantage of the CPE process.

Overall, the SCE proposal was relatively comprehensive as compared to that of PG&E, which lacked critical details around enforcement, specific categories of workers, and how to address issues with support services. Even with these rules in place, it is still an open question as to how this will all play out in practice, including if personnel shift teams. The big question and possible issue was around SCE proposing to allow the firewall to be relaxed in the case of new resource procurement. Even with the CPE not directly focused on new resource procurement, all new resource procurement eventually becomes an existing contract that may need to bid or show into the CPE for Local RA purposes. Knowledge of the evaluation process and the submissions of others will give SCE an advantage to understand how to procure and later bid resources to advantage them for Local RA. CESA thus opposed the exclusion of the SCE’s proposed competitive neutrality rules for new resource procurement, which would advantage SCE in the CPE RFO.

See CESA’s reply comments on September 18, 2020 on the IOU Competitive Neutrality Proposals

LCR Reduction Compensation Mechanism

CalCCA and PG&E co-chaired and convened a working group to develop an LCR reduction compensation mechanism as well as a proposal on the treatment of existing contracts. Specifically, the working group is tasked with addressing the following parameters for the mechanism:

• Address resource cost effectiveness concerns (including local effectiveness and use limitations of a shown resource to be evaluated alongside bid resources)

• Determine how granular the premium should be, potentially differentiated by preferred resource type, new versus existing resources, and/or location (e.g., sub-areas, local areas, or TAC local areas)

• Balance transparency and market confidentiality of the premium, as appropriate

• Determine whether the compensation mechanism would preclude the option for an LSE to both bid and show a resource in the solicitation (or require potential revisions to the iterative process)

• Determine how to best adjust the local compensation from year to year to account for changes in the effectiveness of the resource reducing the local requirements

CESA recommended that, to balance cost-effectiveness and resource effectiveness considerations, the CPE RFO should identify multiple portfolios of bid and shown resources. To balance transparency with confidentiality of market-sensitive information, the local premium for shown resources should be calculated based on base assumptions of a resource class that can be customizable to reflect the specific project value and benefits. Unless substantiated otherwise, a year-to-year adjustment to the local compensation mechanism should not be established and may not be needed. The CPE RFO evaluation criteria should mirror the premium factors in the local compensation mechanism, link to IRP-identified future long-term procurement needs in local or sub-local areas, and adhere to the loading order and SB 1136 statutory requirements to the greatest extent possible. Finally, the working group should consider pathways to maintain the load forecast adjustment process that is specific to an LSE and reflected in their pro rata share of the collective Local RA requirements, and should clarify and discuss the implications of the CPE buying all RA attributes if selected.

See CESA’s informal comments on July 20, 2020 on the CPE Workshop

Parties generally agreed on the use of a pre-determined price or premium for shown resources, though CalCCA questioned whether preferred resources can be evaluated alongside bid resources. CalCCA and SCE similarly commented that the CAISO needs to provide information on effectiveness factors, where it is currently unclear on how they will be used for definitive metrics and evaluation for local reliability. CEDMC added that local effectiveness factors for DR resources would be difficult due to the size and the dynamic nature of their customer mix. SDG&E added that premiums would also come from other LSEs to be able to pay for CPE procurement and compensate more effective portfolios from more effective LSE portfolios. Almost all parties favored grandfathering of legacy RA contracts prior to the decision, though PG&E expressly opposed grandfathering for the full term of an existing contract or the life of an existing resource.

PG&E and SDG&E made a number of upfront eligibility requirements for the mechanism. SDG&E commented that the mechanism should only apply to storage, preferred resources, and grandfathered contracts of existing fossil resources, where shown resources would be contracted for up to three years. PG&E proposed a list of potential criteria, including being a preferred resource, being MCC Category 2 or greater, and being available to self-schedule or economically bid during the availability assessment hours.

On July 27, 2020, a workshop was held. PG&E considered two options for developing a local price, each with drawbacks:

• Cost-based pricing is based on the difference in developing a resource within a local area and a system resource. There are questions about potential data sources, which may be stale or involve non-sensical aggregation.

• Market-based pricing is based on the results of the CPE procurement, which can be simpler from an administrative perspective. Prices may be inflated by market power and affected by gaming.

In order to send correct market signals, the compensation mechanism should be granular in line with sub-local areas, but due to market power, there would be tradeoffs with some aggregation. Gaming should be avoided where resources may bid expensive and show cheap, while resources may be bid to the premium. PG&E shared concerns with translating one set of effectiveness factors into qualifying capacity or price effectiveness adjustments since the CAISO factors are for the single most binding constraint and would be impacted by the portfolio as a whole. As alternatives, PG&E considered peak-, energy-, and technology-based effectiveness factors. A combination of these could work as well. PG&E also proposed an option for an LSE to sbid, and then later show if not selected but not be eligible for the local premium. PG&E discussed these options in concept.

Meanwhile, SDG&E proposed a single local premium rate per local area that is based on weighted average price of CPE-procured resources minus the market-price benchmark in order to limit complexity, regardless of sub-area or technology type. The CPE must identify the RA-only cost of tolling agreements, if necessary. The effectiveness factors attempts to simplify the calculation by taking the ratio of the LCR divided by the total procured and shown resources. Ultimately, the premium is known at a later point.

On September 1, 2020, CalCCA and PG&E submitted the LCR Reduction Compensation Mechanism Working Group Report that mostly focused on the details of CalCCA’s Option 2 proposal where shown resource local attributes are considered alongside bids in the CPE solicitation. Shown resources are set at a pre-determined price and may be rejected by the CPE depending on their value relative to bid resources, with the premium only applied to preferred and energy storage resources in their portfolio. The proposal is summarized below:

Specifically, the pre-determined price is calculated as follows: in Year 1, the median price is used from the last two quarters of the Energy Division PCIA responses for both System and Local RA, and subtract System RA price from Local RA price and multiply by effective MW. With technological granularity being unnecessary, the premium would be determined for each local area or sub-area and the CPE guidelines will be used to evaluate bid resources. Rolling calculations will be made in subsequent years. This pre-determined price would serve as a price cap, where LSEs would be free to bid at a lower price. To mitigate the potential of market power to be reflected in the premium, CalCCA used the median price and the use of additional local area prices if there are too few prices to use. Compared to a cost-based approach, this would be more accurate, effective, and transparent. CalCCA elaborated that under their second option proposal, neither the premium or the MW shown would be discounted, but the CPE could reject the bid, and the premium would be pre-determined and set at the aggregate level, thus protecting confidentiality and avoiding the challenges of technology-specific granularity.

The CAISO-determined-effectiveness factors can scale the percentage to the average effectiveness of the resources procured in the local area. In effect, the MW will be adjusted for effectiveness factors, but there will not be adjustments on a year-by-year basis as such modifications are not the nature of other types of solicitations. Resources committed through a showing would have a three-year commitment. The Local RA premium is paid if the CPE accepts the bid, whereas the LSE would not receive any Local RA premium if rejected.

Finally, CalCCA commented that they view grandfathering as applying to existing contracts, not existing resources. As a result, existing contracts that are shown should be able to access the premium. Whereas the IOUs proposed that they be allowed to show their Local RA attributes to the CPE for no compensation, CalCCA opposed this as creating cost shifts based on how pre-2009 direct-access customers no longer have any obligation to pay for the costs of these legacy resources, leading to them getting the Local RA benefits for free while CCAs pay for them through PCIA rates. 

In effect, the pre-determined price and showing option decouple the System and Local attributes and provide a median value for the Local RA attributes with certainty by removing the median System RA price in the showing price. In this sense, the pre-determined price does not appear to be “premium” but more an accounting-based option to allow the LSE to maintain the System RA attributes and to direct more of the Local RA value to the specific LSE for their bilateral procurement. From a buyer perspective, this leads to more Local RA “uncertainty” based on the TBD effectiveness factors and CPE RFO criteria but it brings more of the Local RA value to the specific LSE if selected under either the bid or show option. Even if the direct procurement incentive is diluted to a lesser degree, it creates incentives for LSEs to procure the most “effective” resources to increase the odds of managing their Local RA costs through self-procurement. There still is a broader concern about advancing the preferred resource procurement policy, but this may need to be achieved through Track 3B RA reform, better linkages between RA and IRP, and shaping of the CPE RFO criteria.

Many of the same perspectives were shared in opening comments as was done through informal comments to the report and during the workshop, but several new perspectives were shared. PG&E proposed to extend legacy treatment to existing contracts entered on or before March 4, 2019 for the full term of the existing contract, while CalCCA argued that existing contracts should not retain special privileges indefinitely. PG&E and SDG&E also expressed concerns that CalCCA’s Option 2 proposal would change the hybrid procurement framework to a full procurement framework by eliminating the voluntarily-show option in the CPE procurement, including for utility-owned fossil resources for no compensation from the CPE. Finally, AReM and MRP expressed that an LCR reduction compensation mechanism may not actually be necessary under CalCCA’s Option 2 proposal, with nothing in the decision requiring it. The use of “stale” benchmark data was a particular concern.

Workshops & Proposals (Track 1-3 of R.17-09-020)

On February 22-23, 2018, a workshop was held on Track 1 proposals submitted by parties. A wide range of ideas was proposed and presented at the workshop. AReM and WPTF proposed a new centralized capacity market operated by the CAISO within a multi-year RA procurement construct, include 3- to 5-year forward capacity auctions. The CPUC’s Energy Division proposed something similar but proposed having IOUs procure residual Local RA on behalf of other LSEs. PG&E, however, proposed a variation of this idea by having the centralized procurement be done for Local RA, which reduces System and Flex RA requirements (to be procured by LSEs) when accounting for Local RA procurements.

As can be seen above, there were a wide range of ideas proposed to be considered for Track 1 and 2 of this proceeding. The unplanned generation retirement issue and CCA migration are key issues that might dominate mind share early on, leading to CESA’s issues to mostly likely be considered later in Track 2. CESA reiterated support for proposals that improves and enhances the Flex RA product, unbundles System and Flex RA, and authorizes RA counting for hybrid storage resources.

See CESA's comments on March 7, 2018 on the Track 1 proposals workshop.

On April 24, 2018, a technical working group meeting was held to have a collaborative in-depth discussion with parties regarding RA program reforms that would maintain reliability while reducing potential costly backstop procurement – a key focus area for the CPUC staff. The working group covered both short-term and long-term solutions. During the meeting, there was also some conflation of the multi-year RA framework with the centralized procurement and LCR study issues, making it difficult what exact problem the CPUC was seeking to address at the time. The CPUC was focused in the working group meeting on maintaining reliability while avoiding backstop procurement because of the growing number of LSEs, lack of system-level visibility of grid needs from the IOUs, and lack of authority over CCAs and ESPs to direct procurement. The central buyer idea did not get much traction from the CCAs and ESPs, who favor self-procurement as much as possible, while the “clearinghouse” idea to procure any RA needs for certain LSEs seemed to be amenable to parties, though much more discussion on the details are still needed.

On June 25, 2018, D.18-06-030 was issued. The CPUC expressed concern about how load migration has been impacting (and will continue to increasingly affect) resource planning for reliability, as CCA expansion continues to grow and needed generators face retirements (with the decision even highlighting two such resources in Ellwood and Ormond Beach). Thus, the CPUC indicated that they decided to make major foundational changes to the RA framework to improve market efficiency and enhance reliability, though they have concerns of the risks of turning to a centralized capacity market due to the state’s renewable goals. However, there is still much to be determined in terms of the success of this new framework, given that the details must be developed in Track 2. Overall, the decision provided guidance on developing a multi-year Local RA framework and central buyer concepts, while kicking most all other issues to Track 2 to allow for more record development.

Importantly, the decision supported implementation of a central buyer for some portion of Local RA, though no specific proposal is adopted. For Track 2, the CPUC seeks detailed proposals and studies that explore the feasibility of a single central buyer or a single center buyer per transmission access charge (TAC) area and how this would fit under least-cost, best-fit criteria. Many parties supported the central buyer concept, generally identifying the CAISO as the best-fitting entity to play this role since it already does so for backstop procurement while not favoring IOUs to play this role. Others expressed a preference for central clearing mechanisms instead of central buyer concepts to procure RA resources for any deficiencies due to the advantages of price discovery.

On July 19, 2018, a workshop was held that focused on multi-year RA and central buyer proposals from the CPUC Energy Division, Calpine, IEP, IOUs, CCAs, ESPs, and CAISO, which will likely dominate the ‘mind-share’ in Track 2. There was a range of views on central buyer proposals, even among IOUs. All parties generally supported a central buyer (except for AReM and Shell Energy, which favored LSE-specific procurement and centralized auctions, respectively) or self-procurement by LSEs (except for PG&E, which favored full frontstop procurement by a special purpose entity through an RFO), but the differences lied in who each party believed should be the central buyer and the central procurement mechanism. “Frontstop” procurement is defined by the CPUC as a central procurement framework that incorporates both LSE self-procurement (if allowed) and residual procurement prior to a backstop role by the CAISO. Parties’ positions on cost allocation, enforcement/penalties, and other procurement framework details (e.g., RA ‘showing’ timeline, load migration true-ups, RA counting) varied based on their position on their preferred central buyer concept.

Notably, only the CPUC Energy Division supported the distribution utility as the central buyer, who would establish an independent procurement arm and be subject to stakeholder and independent evaluator review – an idea that faced resistance at the workshop from non-IOU LSEs. Given the goals of the Multi-Year Local RA Framework above, the decision by the CPUC on the central buyer concept will also need to be considered together, while keeping in mind additional objectives to: ensure independence of procurement by and financial stability of whoever the central buyer is determined to be; facilitate greater transparency to market prices to some degree; support the state’s clean energy and environmental policy goals (which may deter the CPUC from centralized market designs); and provide greater regulatory certainty and equitable cost allocation.

On October 5, 2018, a Ruling was issued that requested party comments on SCE’s central buyer proposal, which the CPUC found to “straddle” the issue of the central buyer taking on a full versus residual procurement role. Under SCE’s proposal, LSEs procure to meet their System and Flexible RA requirements, which could reduce the obligation of the central buyer to procure Local RA if the resource qualifies for Local RA. The central buyer would then procure Local RA on a residual basis up to 100% of established requirements. SCE explained that, by making a voluntary Local RA showing, the LSE is able to retain the System and any Flexible RA counting attributes that are associated with the Local RA resource for its own RA requirements, but also reduce the residual Local RA requirements that the central procurement entity will be procuring for. The procuring LSE would also have the option to either sell the Local RA resource to the central entity or show the resource in each monthly RA showing, which provides flexibility for the LSE to follow their own procurement priorities.

On October 17, 2018, comments were submitted, with the majority of parties in support in some form. Multiple parties, such as PAO, Calpine, CLECA, CalCCA, and SDG&E, shared the view that SCE’s proposal is viable but could reduce the incentive for LSEs to procure Local RA under the load-share methodology for allocating the costs of any residual Local RA need. Instead, these parties recommended that the proposal be modified to credit self-provided Local RA procurement by LSEs to reduce their allocated share of residual Local RA costs. PG&E, AReM, and WPTF shared the concern about potential over-procurement of Local RA. While PG&E favored full procurement by a central entity (PG&E’s proposed Local Comprehensive Procurement Framework) and expressed that the over-procurement risk exists if Local RA procurement is done in an uncoordinated fashion without granular targeting of local needs, AReM and WPTF recommended an alternative proposal toward central capacity markets over bilateral procurement. Other parties also argued that the effectiveness of different resources to meet Local RA needs should also be considered, not just the least-cost resources, and that the dispatch rights and outage procedures should be clarified under residual procurement by a central buyer. Meanwhile, the environmental parties focused on how the central buyer should not procure fossil resources to meet residual Local RA requirements under long-term contracts. Finally, the CCA parties seemed to be supportive of SCE’s proposal on an interim basis and with limits to the IOU if IOUs are positioned as the central buyer (e.g., ‘forced-bid’ RA-only auctions, no more than three-year contracts, public disclosure of IOU RA sales).

On November 21, 2018, a PD was issued that proposed changes to have distribution utilities as the central procurement entity for their respective distribution service areas and to adopt requirements for implementation of multi-year local procurement to begin for the 2020 compliance year. The CPUC would continue to monitor and evaluate the central procurement function and may modify the role or designate a different central buyer as appropriate in future years. As one of the main reasons to designate the IOUs as the central procurement entity, the PD cited the goal of implementing the new central buyer framework by the 2020 compliance year, which rules out the special purpose entity (SPE) and the CAISO as that central buyer, considering the already established expertise of IOUs, the time it would take to make the appropriate changes (e.g., legislation needed for SPE, tariff changes for CAISO), and the CAISO effectively ruling themselves out of this role. Despite acknowledging SDG&E’s concerns regarding debt equivalency and potential financial risk from inverse condemnation of IOUs serving the central buyer role, the PD determined that there is insufficient record or evidence at this time.

The PD proposed that the distribution utility procure the entire amount of required Local RA with each LSE not receiving individual local requirements, in alignment with the “full procurement model” proposed by PG&E and CPUC Energy Division, in contrast to the ‘residual procurement model’ proposed by SCE and others. In effect, the central buyer would act in a backstop role to procure local resources to meet collective deficiencies under the residual procurement model. LSEs that have procured local resources may offer those resources to the central entity by bidding into the procurement entity’s solicitation.  If an LSE-procured local resource is not selected by the central buyer, the local resource would still be eligible to count towards the LSE’s system or flexible RA obligations, if applicable. The PD justified the full procurement model over the residual procurement model as more efficiently procuring necessary and preferred resources at least cost that meet overall grid needs and minimize collective deficiencies, as creating more administrative ease to track local requirements, and as providing equitable cost allocation to address load migration and stranded cost concerns (i.e., adjust cost responsibility based on actual load rather than forecasted load). The PD also reasoned that it cannot reduce backstop procurement risks by just disaggregating local capacity areas under the residual procurement model.  

The PD favored a competitive solicitation over a centralized capacity market or a centralized solicitation. The PD also adopted a pre-approval mechanism similar to the process adopted with the Bundled  Procurement Plan requirements to enable the central buyers to efficiently satisfy the local capacity requirements, while providing assurances for cost recovery and minimizing the need for ex post reasonableness review. A Procurement Review Group (PRG) and Independent Evaluator (IE) would be included as part of this process. The PD stated that a portfolio approval process shall be adopted in a later phase of this proceeding. Finally, the CPUC encouraged (but does not require) central buyers to procure dispatch rights along with RA capacity. To address neutrality, transparency, and anti-competitive concerns of the distribution utility as the central buyer, the PD directed the IOUs to bid their utility-owned resources into the solicitation process at their levelized fixed costs.

CESA flagged several important areas of concern under the proposed framework in the PD that warrant a delay in implementation of the multi-year and central buyer framework. CESA summarized its recommendations as follows:

• The multi-year and central buyer framework should be targeted for implementation in the 2021 RA year to further evaluate the appropriate central buyer entity and continue to explore the merits of the residual procurement model.

• The CPUC should continue to leverage, in appropriate ways, its authority to mitigate any near-term reliability issues through directed procurement of energy storage solutions, hybridization or other tools.

• More granular locational information is needed to support effective Local RA procurement by LSEs.

• The CPUC should systematically direct considerations of preferred alternative resources prior to finalizing any multi-year RA contracts.

• Further clarification and details are needed into the evaluation and selection criteria for the centralized competitive solicitation.

• The Year 3 requirement should be lowered to avoid locking in undesired resources in perpetuity and to allow for implementation of SB 1136 and fleet transformation.

See CESA’s comments on December 11, 2018 on the Proposed Decision

Many parties (28) filed comments on the PD, with most supporting delay or only tentative support on the central buyer proposal as an interim measure, so it appears that there is a consensus on the need to delay and deliberate more. The non-IOU LSEs particularly highlighted issues about how the PD would violate statute around LSE self-procurement. PG&E and SCE said that it could support being the central buyer in the interim, but recommended that the CPUC work to identify a sustainable, long-term central buyer entity going forward. SDG&E was the most reluctant to take on this role, citing financial risk concerns of taking on this large-scale procurement role. A major issue highlighted by many parties surround how LSEs may have reduced incentives to self-procure given the risks of their Local RA resources not being selected in the centralized RFO, which is a concern that also extends to legacy Local RA resources that may only be attributed with System and/or Flexible RA value if not selected in the centralized RFO, putting many of these contracts at risk. Other common themes of concern were the lack of clarifications or sufficiency of the RFO selection criteria and the compressed proposed RA timeline.

Most of the reply comments were ‘me too’ comments that agreed with delaying the central buyer proposal and not having the IOU as the central buyer. The IOUs pushed back against the dispatch rights being auctioned off, as suggested by DMM. Notably, PG&E continued to hold the view that full procurement model is the way to go and that resources should be required to bid at cost since the central buyer framework would in effect be establishing a residual procurement model – i.e., by having all existing Local RA is selected by the central buyer with LSEs bidding their resources in at $0.

On March 4, 2019, D.19-02-022 was issued that adopted requirements for implementation of a multi-year Local RA procurement to begin for the 2020 RA compliance year but importantly punted on adopting a central buyer structure.

On central buyer issues, the CPUC still indicate that they view the distribution utilities as the “most practical, feasible solution” in the near term as the central buyer. The decision did comment on how a special purpose entity (SPE) and CAISO could not readily take on the central procurement role in the near term, and on how a centralized capacity market would not work for targeted local procurement. The adoption of a central buyer structure is delayed to a decision in Q4 2019 following a minimum of three workshops over the next six months, starting in April, to develop workable implementation solutions for the following:

• Identity of a viable central buyer

• Full or residual procurement scope

• Implementable cost allocation mechanism

• Oversight mechanisms

• Eligible resources and selection criteria

• Market power mitigation tools

• Necessary modifications to the RA timeline

The adoption of a central buyer structure is delayed to a decision in Q4 2019 following a series of workshops to develop workable implementation solutions that address the following “challenges” to the Local RA Program:

• Costly out-of-market RA procurement due to local procurement deficiencies

• Load migration and equitable allocation of costs to all customers

• Cost effective and efficient coordinated procurement

• Treatment of existing Local RA contracts

• Opportunity for and investment in procurement of local preferred resources

• Retention of California’s jurisdiction over procurement of preferred resources

In sum, the decision recognized the comments of parties on their concerns with the full procurement model with the distribution utility as the central buyer, as proposed in the original PD. The scope of the workshops reflect how these issues must be addressed prior to the adoption of a central buyer structure.

On April 22-23, 2019, workshops were held to discuss the details of a central buyer framework, including developing consensus on the definitions, merits, and implementation of full versus residual procurement. In each case, the IOUs presented a ‘strawman’ around how LSEs maintain local procurement decisions under any of the procurement models.

In the full central procurement model, the central procurement entity (CPE) has sole responsibility for meeting local reliability compliance requirements on behalf of all LSEs, where resources are selected for most “effectively” meeting local reliability needs by the CPE. The CPE will construct at least two potential portfolios that will meet local reliability needs after considering CAM resources, resources approved in the IRP for reliability, resources procured in the prior CPE annual process, and transmission solutions that meet local reliability. Bidders to the solicitation would include uncontracted generators in the local area, developers of new generation, and LSEs holding local capacity that may also offer their capacity. If the resource is procured by the CPE, the capacity will reduce the LSE’s total procurement obligation of system and flexible needs and will count towards meeting the overall Local RA procurement obligation. The CPE's recommended portfolio will be based on least-cost resources, along with an alternative portfolio with greater consideration of preferred resources. The CPE will present the portfolios in the RA proceeding to the CPUC, in consultation with the CAISO for approval. Costs will be allocated after-the-fact by charging directly to customers or LSEs based on load share, which the IOUs discussed as being simpler, rather than having to track all customer migrations under a residual procurement model. However, there is a risk that existing Local RA contracts may not be selected. 

In the residual procurement model, which most closely resembles today’s model, LSE-specific requirements are allocated by the CPUC and LSEs are required to meet their own obligations. LSEs will have an opportunity to voluntarily show their self-procured capacity in local areas to the CPE, including new resources under contract to meet their requirements. The shown capacity will determine the amount of residual local requirements that must be procured by the CPE, which would then issue a Local RA RFO for the multi-year local residual requirement. LSEs may submit offers for the self-procured capacity that was not shown previously. The CPE would consult with the CPUC and CAISO to select the resources that best fit the reliability needs at least cost. The CPE would allocate procurement costs directly to LSEs based on each LSE's individual Local RA deficiency. LSEs are able to retain and receive the full value of the self-procured Local RA resources. 

In the hybrid procurement model, LSEs have incremental flexibility to utilize owned or contracted local resources to meet system and flexible needs compared to full procurement while avoiding the complexities of residual procurement (i.e., LSEs voluntarily show resources from their portfolio to the CPE to reduce their bundled Local RA obligations). There is no one-for-one credit for Local RA to the LSE showing the resource, but the lack of a local requirement for each LSE makes the program administratively simpler. 

On the second day, more detailed discussion around the benefits and challenges of each model was discussed. The IOUs presented full procurement as promoting system efficiency, minimizing the need for CAISO backstop procurement, equitably allocating costs and benefits, adapting to any level of load migration, and being administratively simple. On the other hand, full procurement may limit fully autonomous procurement decisions. By contrast, residual procurement supports procurement autonomy and limits the scope of CPE procurement but the IOUs discussed how it would be challenging to directly allocate the costs of excess procurement and be subject to CPUC coordination to ensure proper RA obligation allocations. Some common elements of all procurement models were identified:

• Reduces the local requirement by capacity that has been procured through the cost allocation mechanism (CAM)

• Procures only for bundled local resources and reduces total system and flexible requirements when CPE receives the system and flexible attributes with procured resources as well

• Use the CAISO's existing CPM/RMR mechanisms when CPE fails to procure necessary capacity at reasonable prices

• Procures for resource mix necessary to meet local reliability on a three-year forward basis as opposed to one-year backstop basis under CPM/RMR mechanisms

• Explicitly considers resources that may have been procured by individual LSEs

On May 15, 2019, a CCA-facilitated workshop was held, which began with a discussion of the CPE evaluation criteria, which includes accountability, competitive neutrality, expertise, startup costs, authority/jurisdiction, and financial stability, among other things. Based on this, some potential CPEs were eliminated from consideration in CalCCA’s perspective. The CAISO was ruled out because the CAISO was not interested in assuming the role and because FERC jurisdiction scope could be increased. Since only government entities but not all market participants could be part of a Joint Powers Authority, it was ruled out as the CPE. A utility or utility affiliate was also deemed unworkable because of financial ties to one market participant who happens to also be a buyer and seller and thus raises the question of competitive neutrality, even though the IOUs explained that firewalls are in place (e.g., employees with separate functions) to avoid conflicts of interest. CalCCA appeared to favor a not-for-profit entity with an oversight board, a state agency, or an instrument of the state that avoids some of the shortcomings of other entities serving this role.

Meanwhile, CalCCA and the IOUs differed drastically on whether for-profit or not-for-profit entities would be more or similar in cost to implement, including around billing and financial capability of the CPE. TURN noted that the costs may differ depending on whether a full or residual procurement model is used, and CLECA added that cost recovery may not require legislation if the CPE is billing customers or LSEs. Additionally, IEP observed the need for the CPE to have clear accountability lines. Regardless of who takes on the CPE role, all participants agreed that there would be a long implementation timeline (beyond a year), depending on whether legislation and/or procurement processes are needed, though SCE suggested that the distribution utility as the CPE would not require more than 12 months, with the firewalls being one of the few major issues that would need to be addressed. Some stakeholders also commented on the importance of CPUC oversight to ensure alignment with state policies and with LCBF evaluation criteria.

On May 22, 2019, a Shell-facilitated workshop was held to determine consensus definitions for CPE and the benefits and costs of each CPE option. The CCAs and ESPs generally held the view that the IOU as the CPE would not be able to achieve competitive neutrality without complete separation of procurement and ongoing management functions, while the IOUs asserted that CPUC oversight and measures have ensured that IOU procurement on behalf of all benefiting customers has maintained competitive neutrality. Shell also presented on the issue of CPE procurement being subject to CPUC jurisdiction despite limited time to conduct RFOs and get approvals – though the CPUC could define allowable ranges for procurement costs – and introduced the issue of quantity procurement limits for the CPE to limit over-procurement risks. When procuring for multiple attributes of generation supply, SCE claimed that the full or hybrid model would more efficiently and cost-effectively procure resources. Finally, the workshop participants discussed whether an interim CPE should be implemented to bridge the gap until a permanent CPE is established, which some argued would lead to additional administrative costs. Other discussed topics include load migration, CAISO backstop procurement, cost allocation, and price transparency.

On July 17, 2019, informal workshop reports were published, with much of the workshop presentations and summary reports reflecting the perspectives of the facilitators rather than driving toward consensus. The workshops were helpful in flushing out the pros and cons of each central buyer model, but they were less effective in moving stakeholders toward consensus. The CCAs and ESPs generally favored different flavors of a residual procurement model but shared a common preference to not have the distribution utility as the central procurement entity (CPE), while the IOUs were more divided in terms of their preferred approach – i.e., PG&E (full), SCE (hybrid), and SDG&E (residual). Given the lack of directional consensus, we have some concerns that the CPUC may default to their Track 2 PD position of having the distribution utility conduct full central procurement, unless they are persuaded by any new insights from the workshops. Since parties have not budged in their positions on this issue, the CPUC is put into another tough position of making a decision that will be unpopular with a major segment of stakeholders.

CESA expressed our preference for the residual procurement model as best incentivizing new or hybrid resource development and reducing contract uncertainty, which are important objectives to help achieve the state's decarbonization goals and to reduce local market power concerns. Specifically, preferred attributes are better procured and long-term contracting is better secured under a residual procurement model where LSEs show rather than bid their Local RA resources. In addition, some of the limitations of the residual procurement model are likely addressed by improved load forecasting processes adopted in D.19-06-026, more effective RA sales processes between LSEs, and improved guidance from the CAISO on locational effectiveness of RA resources. Generally though, CESA sought greater incorporation of SB 1136 requirements to advance preferred and new or hybrid resource development, whether under the full or residual procurement model. Finally, CESA indicated how we do not oppose the IOUs serving the CPE function, at least in the interim until a permanent CPE is established, which better ensures direct CPUC oversight and enforcement.

See CESA’s comments on August 2, 2019 on the Central Buyer Informal Workshop Reports

In their comments, CalCCA submitted a residual procurement model proposal for a new state entity or an expansion of any existing state entity to serve the CPE function given their competitive neutrality and categorical exemption from the Federal Power Act. The CPE would not procure dispatch rights or impose requirements beyond CAISO must-offer obligation rules.

On August 20, 2019, a settlement conference was held to discuss a settlement proposal developed by CalCCA, Calpine, IEP, MRP, NRG, SDG&E, Shell, Sunrun, and WPTF to discuss the establishment of a residual central buyer structure under the multi-year forward RA framework that would assume a “default” role in procuring residual Local, System, and Flexible RA needs, with LSEs able to continue to procure RA resources to meet their share of a collective RA procurement obligation. The settling parties filed a motion to adopt their settlement agreement on August 30, 2019.

• The central procurement entity (CPE) assumes the obligation to ensure the collective RA requirement is met such that LSE-specific compliance obligations, waiver/penalty processes, and monthly showing processes are eliminated. The CPE would make the annual showing to the CPUC. CAISO backstop procurement is only triggered if CPE is unable to cure CAISO-identified deficiencies or if there are insufficient resources meeting its procurement criteria, including prices reaching above the CPM soft-offer cap on an annualized basis.

• Annual pay-as-bid RFO solicitation will procure for RA-only products, not to exceed three years, from new or existing resources and any necessary maximum import capability (MIC) rights on a least-cost basis. By limiting CPE procurement to three years, new resource investments are encouraged according to the settling parties. Procurement criteria will also consider whether it effectively addresses local area constraints and meets state energy policy objectives, among other potential selection criteria.

• LSE self-procured RA capacity can be voluntarily procured and shown to meet the collective RA requirement (up to 100% of the LSE’s share of the collective RA requirement, including for Local and/or System RA) or may be offered into the CPE solicitation. Administratively-allocated resources, such as those procured through CAM, are deemed as shown RA capacity. If an LSE’s forecast share of the collective RA requirement declines, an LSE will reduce its shown RA in its annual showing to a level not greater than its reduced share of the collective RA requirement, and the excess shown RA must be either transacted with another LSE or offered to the RA CPE in its annual RFO.

• Cost allocation occurs ex post to address load migration, where the LSEs will be charged the same weighted average price for each RA attribute to cover residual RA procurement and location and credited the same weighted average price for a single attribute and location to cover surplus shown RA capacity. The LSE will allocate its total CPE cost to its customers as part of the generation rate and the CPE/CAISO will allocate proportional shares of the deficiency for CPE or CPM/RMR procurement costs.

Notably, the Year 3 Local RA procurement was increased from 50% in D.19-02-022 to 75% under the settlement proposal and was expanded to cover System and Flexible RA procurement requirements in the three-year forward requirements, as follows:

The proposal, however, does not cover the CPE identity, import RA issues, market power issues, or the CPE role in developing and owning new resources. The proposal did lay the principles for the CPE to be an entity that is competitively neutral, independent, and creditworthy, all but calling out the IOUs as an inappropriate entity for this CPE role.

Overall, under the settlement agreement, the RA market is not overhauled, as some parties have proposed to do, but it does position most new storage procurement to come from CCAs by preserving self-procurement authority and any residual procurement to some unidentified central entity. While the settlement agreement addresses stranded cost/investment risk, it is unclear on how well storage is positioned under the proposed structure without more explicit criteria to ensure that the central buyer only procures for least-cost reliability resources, where storage has the added benefit of supporting the state's decarbonization goals.

CESA focused on key modifications to the Joint Settlement Agreement to ensure that these dual goals are better incorporated into the state’s capacity and reliability planning framework.  Specifically, CESA recommended the incorporation of SB 1136 requirements in the solicitation evaluation criteria that is part of the proposed annual pay-as-bid RFO solicitation. Additionally, CESA recommended that the CPUC reject the increase in the Year 3 Local RA requirement to 75% of the multi-year forward requirements for Local RA.  Finally, CESA recommended that the Joint Settlement Agreement be modified to set the principles for the CPE entity to include market and procurement experience. Our recommendations outlined would also apply if the CPUC alternatively considers the adoption of a full central buyer structure.

See CESA’s comments on September 30, 2019 on the Joint Settlement Agreement

On March 26, 2020, a Proposed Decision (PD) was issued on establishing a new Local RA “hybrid” central procurement structure, seeking to resolve the two-year-long discussion on central procurement schemes. The CPUC proposed a hybrid central procurement framework that “strikes a balance” between the residual and full procurement options while addressing the issues known for the Local RA market (i.e., equitable cost allocation, market power mitigation, self-procurement autonomy). Notably, the PD rejected the Settlement Agreement put forth by CalCCA, Calpine, IEP, MRP, NRG, SDG&E, Shell, and WPTF (the Settling Parties) to institute a residual central buyer structure on the following grounds:

• Settlement process involved procedural flaws due to insufficient opportunity to discuss new settlement agreement and to insufficient representation (i.e., only 8 parties included).

• The identity of the CPE entity was not provided.

• The Settlement Agreement does not a compromise between full and residual models.

• The Settlement Agreement would remove LSE incentive to procure via voluntary showings, leading to potential overreliance on CAISO procurement and unjust cost shifting.

• The Settlement Agreement covered out-of-scope issues such as multi-year requirements expansions without record support.

Just as with the previously-proposed full procurement model, many of the same problems are present in the currently-proposed hybrid procurement model. CESA expressed how the PD would disincentivize LSE procurement of local resources due to uncertainty related to whether the procured resources will be selected by the CPE (under the bidding option) and how much the procured resources will count toward their own share of the Local RA requirement (under the voluntary showing option).  In turn, LSEs and developers face uncertainty to the value of local resources, leading to inefficient and/or excess procurement by the LSEs and creating “leaning” issues among LSEs. CESA thus opposed the PD unless substantially modified. Specifically, CESA recommended that the collective Local RA requirements should be established after accounting for new long-term resource procurement from the IRP. CESA also recommended that the solicitation criteria should be further refined to ensure that Local RA procurement by the CPE aligns with IRP decarbonization goals while removing dispatch rights as a preferred criterion for the CPE solicitation.

Unanimous opposition to the PD was expressed by companies and trade associations representing resource developers/providers, independent power producers, and non-IOU LSEs (i.e., CCAs, ESPs) due to the PD removing the incentive for procuring local preferred resources and the uncertainty created for existing and under-negotiation resources under the proposed hybrid model. Many opponents to the PD also expressed how the CPE criteria lacked clarity or accounting of all the various factors to ensure new resource development, mitigate unintended impacts of including dispatch rights as an optional bid parameter, and a competitive level playing field. CalCCA, Settlement Parties, and AWEA-CA, meanwhile, insisted on either retaining the existing bilateral RA structure or adopting the residual procurement model given that there was limited opposition to the settlement agreement.

Several parties were in support of the PD, including SCE, PG&E, and the ratepayer and consumer groups (e.g., PAO, CLECA). The supporting parties generally did not offer any specific comments other than to request certain clarifications, though SCE emphasized that the IRP, not the RA Program, should incentivize the deployment of resources needed for long-term reliability. While preferring the residual procurement model, SDG&E narrowly supported the determination that the Local RA-only central procurement framework should not be adopted in SDG&E’s TAC area at this time, expressing how it does not want to play a CPE role when it is not projected to serve much load going forward.

Monterey Bay Community Power (MBCP) was the only party who submitted a more detailed counterproposal to the one included in the PD, whereby the CPUC would implement a full procurement model. In this alternative proposal, the IOUs would be temporarily installed as the CPE through 2025 to procure the full amount of Local RA through a single price clearing auction in each local area. Should the initial auction fail to procure sufficient Local RA, the CPE will, after giving LSEs an opportunity to procure necessary resources, issue an RFP for resources (including potentially attributes other than Local RA and for longer contract terms) to meet the remaining Local RA requirements. In the long term, the CPUC should continue examining and make recommendations by 2025 for full regional RA procurement, potentially an independently managed central capacity market covering all RA needs for entire CAISO grid.

CESA observed that many parties highlighted the flaws of the “hybrid” procurement model as proposed in the PD for its lack of clarity on a number of issues, which point to a need to make major refinements and modifications to the PD’s proposed hybrid procurement model prior to adoption and implementation by the 2023 RA compliance year. Given the multitude of issues that need to be worked through, CESA suggested that there may be sufficient grounds to delay implementation of the central procurement structure by one year and/or to consider whether a more appropriate middle-ground solution can be reached between the PD’s hybrid procurement model and the Joint Settlement Agreement’s residual procurement model, which create broader consensus of parties. Specifically, CESA also commented that a one-for-one crediting system should be maintained for LSEs that opt to show bilaterally procured resources, dispatch rights should be removed as a bid parameter, and the CPUC should defer extension of the multi-year requirements to other RA products at this time.

See CESA’s comments on April 15, 2020 and reply comments on April 20, 2020 on the Proposed Decision

On June 17, 2020, D.20-06-002 was issued that adopted implementation details for the central procurement of multi-year Local RA procurement to begin for the 2023 compliance year in the PG&E and SCE distribution service areas. The decision established the following characteristics for the hybrid central procurement structure: 

• Central Procurement Entities (CPEs): Given the potential federal jurisdiction issues of a centralized capacity market and the time it would take to establish a separate entity, the CPUC determined that the distribution utilities are the central procurement entity candidates with the resources, knowledge, and experience to procure Local RA resources on behalf of all LSEs in the near term. Nevertheless, the CPUC noted that SDG&E’s TAC area is unique in that the local RA requirements typically meet or exceed the system requirements, such that LSEs would have little procurement autonomy for System and Flexible RA under a hybrid model. Hence, SCE and PG&E were appointed the CPEs of their respective TAC areas.

• Procurement mechanism: The CPUC adopted an RFO process because it gives the CPE the flexibility to select resources based on multiple targeted criteria (e.g., costs, local needs, broader environmental goals). The CPE is permitted to conduct multiple solicitations per year, as needed.

• Resource showings: In lieu of LSE-specific Local RA obligations, LSEs may bid self-procured Local RA into the CPE RFO, where the resource would count on a 1-for-1 basis to reduce collective Local RA requirements by TAC area, if selected in the RFO. Alternatively, LSEs could voluntarily show self-procured resources for System and Flexible RA, with these resources potentially counting toward overall Local RA requirements but with no guarantees that they would count for Local RA on a 1-for-1 basis. Finally, an LSE could only show the resource for System and Flexible needs but not for Local RA needs. An LCR reduction compensation mechanism will be developed to support local preferred resources.

• Cost allocation: The cost allocation mechanism (CAM) should be used for cost allocation for any CPE procurement, moving RA costs from generation rates to distribution rates. Costs will be allocated on an ex post basis based on an LSE’s peak load share for any resources procured by the CPE.

• Evaluation of bids: The CPE should evaluate resources using the least cost best fit methodology and including the following criteria: (1) future needs in local and sub-local areas; (2) local effectiveness factors; (3) resource costs; (4) operational characteristics of the resources; (5) location of the facility; (6) costs of potential alternatives; and (7) GHG adders. The criteria included citations to the loading order and prioritization of preferred resources over fossil generation but also referenced consideration of energy limitations. Despite insufficient record to require CPE to acquire dispatch rights, dispatch rights can be included as an optional term that is encouraged. The decision also required distribution utilities serving as the CPE to bid its own resources into the solicitation at their levelized fixed costs.

• Oversight on CPE procurement: The Procurement Review Group (PRG) assumes the role to monitor and oversee the CPE through the RFO process, in consultation with Energy Division and an independent evaluator (IE). A portfolio approval process should govern when a procurement action by the CPE is deemed reasonable and pre-approved. Finally, the CPE should have discretion to defer procurement of a local resource to CAISO’s backstop mechanisms without penalties if bid costs are deemed unreasonably high, so long as the CPE made reasonable efforts to secure capacity.

• Transition to the centralized structure: For 2020, the 50% local requirement is eliminated for the 2023 compliance year; however, the 100% two-year requirement will remain such that LSEs will be responsible for 100% of their 2021 and 2022 local requirements in 2020, and 100% of their 2022 local requirements in 2021. Therefore, the CPE will begin local procurement responsibilities in 2021 for the 2023 and 2024 compliance years. The multi-year requirements are otherwise maintained in following years: 100% in Year 1, 100% in Year 2, and 50% in Year 3. Treatment of existing Local RA contracts will be handled at a later stage in the RA proceeding.

Relative to the PD, the decision was revised that declined to adopt a one-for-one credit for not accounting for a resource's effectiveness at reducing LCR needs and instead adopted an “LCR reduction compensation mechanism” to be determined in a working group process by September 1, 2020 that compensates LSEs for shown local preferred resources that provide ratepayer value and reflect the additional costs of procuring resources close to load. After accounting for local effectiveness and use limitations, the working group will need to determine the local premium’s granularity and year-to-year changes, among other things. The CPUC discussed how giving local resources inflated local capacity prices would not resolve market power issues. The decision also added consideration of how the "orderly retirement" of gas could be considered within or outside of the adopted CPE structure. The treatment of existing Local RA contracts was still to be determined in the working group process, noting that they are not inclined to grandfather resources that are not currently online. Other than some added details related to the process and options to show or bid Local RA resources, the decision was otherwise unchanged.

Overall, the final decision did not represent the wholesale change we sought given the significant opposition to the PD for the lack of clarity and incentives for new resource procurement. Rather, an unclear and to-be-determined cost-based “local premium” will be developed in future RA Working Groups in the CPUC proceeding R.19-11-009 for local energy storage and preferred resources to not “discourage” such development. However, it was entirely unclear on what is within the scope of this local premium or adder. Other than this “silver lining”, the decision has the potential to create uncertainty related to the Local RA value of existing and new storage resources. The two rounds of revisions, however, suggest that the CPUC was acutely aware of coordination and alignment of IRP long-term planning and procurement with the RA Program, particularly as it relates to gas retirements and preferred resource procurement. Additionally, the decision created uncertainty of how existing tolling agreements would be addressed with the inclusion of dispatch rights as an encouraged term. Whether the multi-year forward obligations should be extended to System/Flexible RA was deferred at this time, thus maintaining the current one-year-ahead requirement.

LCR Reduction Compensation Mechanism

CalCCA and PG&E co-chaired and convened a working group to develop an LCR reduction compensation mechanism as well as a proposal on the treatment of existing contracts. Specifically, the working group is tasked with addressing the following parameters for the mechanism:

• Address resource cost effectiveness concerns (including local effectiveness and use limitations of a shown resource to be evaluated alongside bid resources)

• Determine how granular the premium should be, potentially differentiated by preferred resource type, new versus existing resources, and/or location (e.g., sub-areas, local areas, or TAC local areas)

• Balance transparency and market confidentiality of the premium, as appropriate

• Determine whether the compensation mechanism would preclude the option for an LSE to both bid and show a resource in the solicitation (or require potential revisions to the iterative process)

• Determine how to best adjust the local compensation from year to year to account for changes in the effectiveness of the resource reducing the local requirements

On July 27, 2020, a workshop was held. PG&E considered two options for developing a local price, each with drawbacks:

• Cost-based pricing is based on the difference in developing a resource within a local area and a system resource. There are questions about potential data sources, which may be stale or involve non-sensical aggregation.

• Market-based pricing is based on the results of the CPE procurement, which can be simpler from an administrative perspective. Prices may be inflated by market power and affected by gaming.

In order to send correct market signals, the compensation mechanism should be granular in line with sub-local areas, but due to market power, there would be tradeoffs with some aggregation. Gaming should be avoided where resources may bid expensive and show cheap, while resources may be bid to the premium. PG&E shared concerns with translating one set of effectiveness factors into qualifying capacity or price effectiveness adjustments since the CAISO factors are for the single most binding constraint and would be impacted by the portfolio as a whole. As alternatives, PG&E considered peak-, energy-, and technology-based effectiveness factors. A combination of these could work as well. PG&E also proposed an option for an LSE to sbid, and then later show if not selected but not be eligible for the local premium. PG&E discussed these options in concept.

Meanwhile, SDG&E proposed a single local premium rate per local area that is based on weighted average price of CPE-procured resources minus the market-price benchmark in order to limit complexity, regardless of sub-area or technology type. The CPE must identify the RA-only cost of tolling agreements, if necessary. The effectiveness factors attempts to simplify the calculation by taking the ratio of the LCR divided by the total procured and shown resources. Ultimately, the premium is known at a later point.

Finally, CalCCA proposed the most comprehensive solution. Based on the decision, CalCCA interpreted the decision to allow for one of two options. Under Option 1, shown resource local attributes are must-take for the CPE, but the premium must be transparent and pre-determined, adjusted for resource effectiveness and use limitations. Option 2 is discussed further below.

CESA recommended that, to balance cost-effectiveness and resource effectiveness considerations, the CPE RFO should identify multiple portfolios of bid and shown resources. To balance transparency with confidentiality of market-sensitive information, the local premium for shown resources should be calculated based on base assumptions of a resource class that can be customizable to reflect the specific project value and benefits. Unless substantiated otherwise, a year-to-year adjustment to the local compensation mechanism should not be established and may not be needed. The CPE RFO evaluation criteria should mirror the premium factors in the local compensation mechanism, link to IRP-identified future long-term procurement needs in local or sub-local areas, and adhere to the loading order and SB 1136 statutory requirements to the greatest extent possible. Finally, the working group should consider pathways to maintain the load forecast adjustment process that is specific to an LSE and reflected in their pro rata share of the collective Local RA requirements, and should clarify and discuss the implications of the CPE buying all RA attributes if selected.

See CESA’s informal comments on July 20, 2020 on the CPE Workshop

Parties generally agreed on the use of a pre-determined price or premium for shown resources, though CalCCA questioned whether preferred resources can be evaluated alongside bid resources. CalCCA and SCE similarly commented that the CAISO needs to provide information on effectiveness factors, where it is currently unclear on how they will be used for definitive metrics and evaluation for local reliability. CEDMC added that local effectiveness factors for DR resources would be difficult due to the size and the dynamic nature of their customer mix. SDG&E added that premiums would also come from other LSEs to be able to pay for CPE procurement and compensate more effective portfolios from more effective LSE portfolios. Almost all parties favored grandfathering of legacy RA contracts prior to the decision, though PG&E expressly opposed grandfathering for the full term of an existing contract or the life of an existing resource.

PG&E and SDG&E made a number of upfront eligibility requirements for the mechanism. SDG&E commented that the mechanism should only apply to storage, preferred resources, and grandfathered contracts of existing fossil resources, where shown resources would be contracted for up to three years. PG&E proposed a list of potential criteria, including being a preferred resource, being MCC Category 2 or greater, and being available to self-schedule or economically bid during the availability assessment hours.

CPUC-CAISO Alignment (R.17-09-020)

Track 1

On February 22-23, 2018, a workshop was held on Track 1 proposals submitted by parties. A wide range of ideas was proposed and presented at the workshop:

• Avoiding costly backstop procurement: AReM proposed aligning the processes to permit LSEs to complete RA contracting before the CAISO acts on RMR determinations. ORA also echoed concerns about avoiding RMR and CPM designations through RA reforms and improvements to the CAISO and IRP analysis process, but was generally open to different solutions.

• Planning standards: The CAISO proposed that the CPUC consider a 1-in-5 peak demand for shoulder months (e.g., May, June), due to their greater weather variability, for RA planning purposes. For similar reasons, Calpine presented modeling and analysis on how the current 15% PRM for all months was insufficient in non-summer months, leading the CAISO to rely on non-RA resources during high-load days. Calpine thus proposed a new reliability standard that may differentiate PRM needs by month to ensure sufficient RA resources are available to meet load during these days.

• RA hours and CAISO availability assessment hours: The CAISO presented their recommendations for RA availability assessment hours to be between 5-9 pm year-round (changed from 4-9 pm), while the CPUC Energy Division and SCE presented on the need to align RA hours – i.e., from 1-6 pm for April-October and from 4-9 pm for January-March and November-December – with the CAISO availability assessment hours (AAHs), during which the CAISO applies a penalty for failing to meet must-offer obligation. This issue is especially relevant to DRAM contracts, which are required to perform according to the CPUC’s RA measurement hours and thus required the CAISO to file a waiver request at FERC for these contracts.

• Late options for LCR and FCR studies: The CPUC’s Energy Division presented several options for the treatment of late LCR and FCR studies and how the RA allocation and procurement process would accommodate the late delivery of these studies.

On May 15, 2018, the CAISO presented on its draft recommendation for setting the system and local availability AAH, which it proposed as setting for 5 pm to 9 pm for both the winter and summer, marking a marked change from 2017 when AAH was set differently for the winter and summer seasons. The AAH is determined based on the hours of greatest need to maximize the effectiveness of the availability incentive structure – i.e., top 5% of load hours within each month from 2017 through 2021.

On June 25, 2018, D.18-06-030 was issued that approved the PD with only minor clarifications and modifications. Among other things, the decision adopted revised RA measurement hours to align with the CAISO’s revised AAHfrom 4-9 pm for all months for 2019. To address future alignment issues, the decision adopted a process to ensure alignment for qualifying capacity (QC) purposes. This determination was widely supported by parties.

Demand Response Qualifying Capacity (QC) Methods

Background

Demand response (DR) resources must meet the following operational requirements to qualify for Resource Adequacy (RA), pursuant to D.14-06-050 (Appendix B), D.14-03-026, D.14-12-024, and Resolution E-4728:

• Dispatch at least four consecutive hours during the availability assessment hours (AAH)

• Dispatch up to 24 hours per month

• Sustainable at maximum power output

• Sustainable over three consecutive days

Resources may be aggregated, but as a whole, they must demonstrate eligibility such that the resource can provide the full qualifying capacity (QC) throughout the RA AAH. 

Track 2 will consider qualifying capacity counting conventions and requirements for DR resources:

• What rules should be required for third-party DR (e.g., operation, testing)?

• How should load-modifying DR be counted?

• Are modifications to the load impact protocols (LIPs) needed (e.g., to ensure DR resources provide local and system reliability benefits)?

PG&E, CPower, and PAO volunteered to co-chair the working group.

Working Group

On February 13, 2020, a working group meeting was held to discuss the current issues and rules for third-party DR RA values and the load-modifying framework. Pursuant to D.19-06-026, the CPUC staff presented an overview of third-party DR resources and how they receive QC value today, as well as on the important role of load impact protocols (LIPs) in feeding into the 10-year IRP projections and 3-year RA planning. Third-party demand response providers (DRPs) have raised concerns that the LIP process is not the right methodology for valuing their resources as it does not accommodate their various business models or customer movements. For example, C&I DRPs will build bottom up resource capabilities to match contracted resource commitments that may not be known during the time of LIP study and may contain a completely different customer set. Additionally, it has been flagged that the LIP process is too slow for project developers to receive RA credit for projects coming online, more closely to delivery periods as is happening with the plethora of resiliency-based projects being sought by customers and LSEs.

CEDMC presented proposals to assess the accuracy of LIPs by comparing ex ante load impacts for a given year to the same-year ex post load impacts. If shown to be inaccurate, the CPUC should consider improvements or another approach altogether. LIPs, if applied, should require analysis of all sub-LAPs, not only local capacity areas (LCAs), in order to enable more accurate local area reliability planning. To enable third parties to use LIPs, CEDMC argued that common data must be made publicly available (e.g., temperature data by weather station), composition of Demand Response Measurement & Evaluation Committee (DRMEC) should be expanded to include key trade organizations and CAISO, and confidentiality of DRP data must be protected via non-disclosure agreements (NDAs).

Finally, CEDMC commented on only using the applicable protocols and shared specific changes to some of the LIP protocols, such as in reflecting how the third-party DRP portfolio may be fluid (i.e., not stable programs like those of the IOUs). When LIPs are applied to third-party DR resources in RFOs, CEDMC commented on how they are unable to respond due to the lack of historical data from new resources. As a result, third-party DRPs should be allowed to enroll new customers year-round and respond to RFOs.   

CAISO advocated for the use of an ELCC study for DR due to their concern of the increasing reliance on DR resources for capacity despite the variability of DR output and limitations on DR availability. Certain local areas will require resources to be available with significant frequency and for long durations, illustrating the importance of assessing a resource’s capacity value based on its availability. While LIPs do not address interactive effects, CAISO believed that capacity value must be assessed in the context of other energy and availability-limited resources due to saturation effects. An ELCC study assessment can thus inform program design features and overall investment decisions.

PG&E discussed two proposals. First, PG&E proposed enhancements to the current RA requirements for DR resources that: (1) demonstrate “typical” (not optimal) resource performance; and (2) meet minimal testing requirements of once per quarter and meet a minimum four consecutive hour test during the availability assessment hours. As justification, PG&E argued that DR resources should be measured in a comparable manner for RA purposes, regardless of whether it is an IOU, CCA, or third-party program or portfolio participant. Second, while not a specific proposal, PG&E raised a question around how the planning reserve margin is applied to DR resources. Considering the way the supply-side DR resource is grossed up, PG&E argued that the “effective” PRM may fall below 15% in certain cases.

On February 21, 2020, in Track 2 proposals, OhmConnect proposed that RA templates should allow for DR to be counted toward an LSE’s Local RA obligation and that LSEs should compute avoided T&D losses in RA compliance templates.

On February 24, 2020, a follow-up working group meeting was held on February 24 where CEDMC countered PG&E’s proposal with the following:

• Two test events per year, in either of the first two months of the delivery period and August

• Two-hour test events

• Testing to full contract capacity but not all resources simultaneously

• Test event is foregone if one-hour full market dispatch, with the ability to combine test event to market dispatch

• Performance is measured as two-hour average

• Customer movement is prohibited in a month, except when new customers are added to resource or when customers drop out

Follow-up discussions were also made on developing confidentiality rules for third parties (D.06-06-006) and revising the composition of the DRMEC to market participants as well.

On March 11, 2020, a final report was submitted by PG&E, CPower, and PAO. CESA commented that the CPUC should prioritize transparency and efficiency in the processes required to determine the QC of DR resources. CESA supported the application of the DRAM paradigm of QC methodologies for all third-party-provided DR that relies on performance and testing requirements for capacity valuation, but minimum energy requirements should be deferred at this time. CESA considers this approach would minimize the risks associated with market limitation and customer attrition while ensuring the proper accounting of the reliability provided by DR assets. How BTM storage is accounted in the load forecast and ensured against double counting should be investigated in Track 3 of this proceeding. On CAISO’s proposal, CESA commented that the ELCC methodology cannot capture the differentiated impact of a range of demand response resources.

See CESA’s proposal on February 21, 2020 and comments on March 23, 2020 on the Working Group Report

Meanwhile, PG&E proposed enhancements to existing operational requirements and resource aggregation requirements that demonstrates “typical” (not only optimal) resource performance under a variety of weather and other conditions. The testing requirements would be initially set at once per quarter for four consecutive hours test during the AAH. After establishing a record of stable performance, the testing requirements would be reduced to once per year for minimum two consecutive hours test during the AAH. The CPUC Energy Division had two proposals. First, Proposal B from the RA team proposed to set a QC methodology based on a four-hour dispatch or test event during the RA measurement hours for three days during the peak summer months of July through September, justified based on the dynamic capabilities of DR resources based on weather, customer enrollment, etc. Second, Proposal C from the DR team sought to rely on ex post performance and testing requirements through contractual enforcement and least-cost dispatch, similar to those in place for IOU LCR contracts for DR resources.

Instead of the Staff Proposal, the coalition, including CESA, proposed that the QC would equal the contract value, but thereafter, rigorous testing and penalties should be used instead that offers administrative simplicity and flexibility. A two-tier testing structure could be adopted to reward good performers:

• Tier 1: Incumbent DRPs with well-performing resources would be subject to a single two-hour test or market dispatch per season (August and winter).

• Tier 2: New entrants, incumbents with underperforming resources (i.e., less than 75% of QC), or DRPs with year-over-year capacity expansion exceeding 50% should be subject to quarterly two-hour tests or market dispatches. Once resource performance exceeds 75% for two consecutive quarters, the resource would be subject to Tier 1 treatment.

To ensure performance up to contract capacity, the coalition offered the following gated approach:

• Gate 1 (QC): If capacity falls below 90% of the contract capacity included in the year-ahead supply plan, then a penalty would be applied.

• Gate 2 (QC): If capacity included in the month-ahead supply plan falls below 90% of the capacity included in the year ahead supply plan, then a penalty would be applied.

• Demonstrated Capacity (DC): Similar to DRAM, a prorated payment would be applied for DC between 70% and 90% of QC. Additional penalties would be applied for DC below 70%.

Sunrun and Enel X presented on how LIPs could be applied for BTM storage-backed DR resources. Sunrun recommended that QC be measured based on the full output of the BTM resource, using the traditional metering generator output (MGO) methodology, which considers the output of the BTM resource before and after a DR event, without a baseline. Additionally, Sunrun advocated for a clear and consistent RA incrementality directive, where load forecast assumptions must be reconciled for existing BTM resources in a new aggregation.

On June 30, 2020, D.20-06-031 was issued that found that adopted PG&E’s proposal with the modification that all third-party DR resources procured by non-IOU LSEs shall be subject to the ‘stricter’ testing regime. Beginning in the 2021 compliance year, all third-party DR resources procured by non-IOU LSEs are required to dispatch for four consecutive hours during the RA measurement hours in every quarter of the delivery year, or via equivalent out-of-market tests. Tests must be done at the resource ID level and all resources within the same sub-LAP must be dispatched concurrently. Test results must be submitted by the end of the quarter following the quarter in which the test dispatch occurs. This approach was pursued because criteria to differentiate between “new and changing” resources required more discussion. Fortunately, the CPUC did not find sufficient record evidence to adopt minimum dispatch requirements at this time.

CESA found many issues with the DR-related determinations. Significantly, the testing regime should remove reference to type of LSE in making the QC determination and instead set the level of testing requirements based on performance. Overall, the changes represented more stringent testing and dispatch requirements, where DR resources are currently required to be tested once per year for two consecutive hours.

See CESA’s comments on June 11, 2020 on the Proposed Decision

Load Impact Protocol (LIP) Evaluation Plans for Third-Party Demand Response Providers (DRPs)

For non-DRAM resources pursuant to D.19-06-026, third-party DRPs are required to obtain QC for their resources through LIPs. The CPUC Energy Division initiated a process to address issues and eventually implement LIPs for third-party DRPs and non-utility LSEs seeking QC for non-DRAM resources. Third parties will have until May 15, 2020 to submit their draft final evaluation plans for LIPs and until October 1, 2020 to submit names of their capacity buyers and associated MW values. Non-IOU LSEs will have until September 1, 2020 to make capacity allocations. These LIP processes are established for 2020 to apply to the 2021 RA year only.

On January 24, 2020, a conference call was held to discuss these proposals.  To the extent some of the desired changes fall within staff discretion and can be feasibly accomplished within the schedule, the CPUC will publish them by January 31, 2020, in time for the LIP filings in April 2020. CPUC Energy Division noted that, to the extent some of the desired changes fall within Staff discretion and can be feasibly accomplished within the schedule, ED will publish them by February 7 in time for the LIP deadlines. Proposals that cannot be made under Staff discretion or are infeasible within the 2020 schedule may be taken up via a CPUC process that is yet to be determined.

On February 10, 2020, CEDMC and Joint DR Parties submitted a letter on to request relief for third-party DRPs for a time extension for submitting LIP evaluation plans until the CPUC staff has adopted a public process (e.g., R.19-11-009) for developing a methodology to evaluate QC values for third-party DR resources in non-DRAM solicitations. The Joint Parties argued that this extension is necessary in light of the lack of guidance from D.19-06-026 on how the application of the LIPs is to take place specific to third-party DR resources, especially considering the absence of CPUC precedent on applying LIPs for entities other than IOUs. An additional public process is needed to develop such methods that also protect the proprietary information of third-party DRPs.  The CPUC Executive Director denied the request on February 19 due to the request involving various factual and legal arguments that warrants discussion and resolution in a formal proceeding.

On February 28, 2020, third-party DRPs submitted their draft LIP evaluation plans. Many key observations were made on how to incorporate growth expectations, challenges with data access since the IOUs do not provide comprehensive account information, and uncertainty created by ex ante QC estimation based on test events only for 2019. For storage providers, emphasis was placed on how storage discharge can be directly sub-metered and measured, where ex ante estimates can be assessed based on empirical ex post impacts. Battery storage dispatch, however, is not subject to customer fatigue or weather/day match challenges unlike traditional DR loads, they said.

A number of parties, including the CPUC Energy Division and IOUs, disputed the lack of baselines used by batteries using sub-metering methodologies and the lack of load drop verification or reference load (i.e., incremental). PAO elaborated that LIPs should be determining why load reduction occurred and not just what load was dropped. The CAISO recommended that the CPUC reject the proposals by Tesla and Sunrun, which they found to create a third, distinct category of DR that acts as a load-modifying DR that would also receive a QC to meet RA requirements in violation of the bifurcation decision (D.14-03-026) and creating double-counting concerns. Additionally, the CAISO discussed how it will implement a new load-shift product for storage-backed DR participating in the CAISO markets in Fall 2020. The CPUC staff also broadly commented on how enrollment forecasts and scenarios should be provided to defend assumptions.

On May 29, 2020, supply-side DR providers submitted their final LIP reports for resources seeking 2021 RA qualifications. Among relevant storage parties, Tesla sought up to 20 MW of QC value for the 2021 RA year and proposed the use of a submeter to measure battery performance directly rather than measuring customer consumption at the point of the utility meter and using regression analysis to account for other factors. However, rather than integrating into the CAISO market, Tesla’s DR program was proposed as a market-informed load-shifting product that responds to market conditions when certain “dispatch thresholds” are exceeded. Specifically, to calculate the ex ante QC, the three prior non-event weekdays will be used as a reference to establish a baseline to measure performance on dispatch days, deviating from the 10-day approach because the days closer to the dispatch day are more likely to have similar conditions and experience. Due to the lack of direct operating history in California, Tesla proposed to use the operating history of similar products deployed in New England to arrive at an ex ante estimate. The CPUC Energy Division raised the issue that Tesla must demonstrate incrementality to the IEPR forecast if not participating in the CAISO wholesale market. In response, instead of using the CEC’s IEPR forecast assumptions (i.e., 6-kW residential storage discharging to serve load, cycling in four summer months, based on NREL SAM profiles), Tesla proposed to use its own California baseline data for being more accurate for the homes participating in its aggregation program, rather than using a “typical” home assumed in the CEC IEPR forecast. Accounting for performance factor, energy availability, and reference loads, Tesla estimated 2.728 kW QC per 5-kW battery.

Sunrun, meanwhile, initially proposed a submetering methodology that a baseline is not needed and that ex ante estimation would be based on empirical ex post results. The CPUC Energy Division continued to focus on how Sunrun must measure baseline load to determine a reference value for the DR counterfactual. As a result, the final evaluation plan was modified to use a traditional 10-in-10 baseline and assume daily cycling with discharge in the 5-9pm period that does not include exports, resulting in lower numbers (by more than 60% in capacity value).

Finally, SCE submitted their final report to establish ex ante load impact estimates for 2020-2030 based on 2019 deliveries of BTM storage-backed DR aggregator contracts with Stem and Swell. These storage contracts, along with non-storage DR resources (NRG), SCE expects up to 61 MW of QC in September from 2022-2030, with the estimated load impacts not varying substantially across weather scenarios. Since aggregators acquire customers, SCE did not forecast customer enrollment and instead calculated ex ante load impact estimates based on expected future impacts tied to constant per-customer impact assumptions and forecasted contract capacity. Nexant also reported that portfolio-adjusted impacts (i.e., those that exclude CPP customers to avoid double counting) are 2.7 MW lower than impacts that include all participants, though such adjustments are not needed for future contracts that are assumed to not have any CPP customers. Overall, this Nexant methodology differs from the previously-proposed control-group approach.

On June 30, 2020, D.20-06-031 was issued that deemed it unnecessary to pursue a significant deviation from the LIPs methodology at this time, although improvements or alternatives to the protocols may be considered in the future. Instead, a few clarifications were provided. The LIP methodology was modified to require ex ante and ex post load impacts at the sub-LAP level and allow for mid-year updates to reflect customer enrollment changes, with the LIP results updated if the QC values vary by more than 20% or 10 MW, whichever is greater. The details will be defined in a future working group process in Track 4 of the proceeding. For resources without historical performance data or existing resources with significantly different expected performance from prior performance, the provider can use either historical performance for similar resources operated by them in the past, or publicly available data that best represents the anticipated performance of such resources. To treat all DR resources equally with respect to transparency, the decision adopted a requirement that LIP reports and the QC values from a DR provider’s LIP results shall be posted publicly to the maximum extent allowable.

Unfortunately, the use of LIPs continued. Greater clarity on LIPs without historical performance is needed in the near term while the use of performance-based and measured approaches should be revisited in the near future.

See CESA’s comments on June 11, 2020 on the Proposed Decision

Effective Load Carrying Capability (ELCC) Modifications

Background

On January 21, 2020, a Scoping Memo was issued that divided the proceeding into four tracks. Track 2 will consider qualifying capacity (QC) counting conventions and requirements for solar and wind resources and address the following questions:

• Should marginal rather than average effective load carrying capability (ELCC) values be used for wind and solar resources?

• If so, how should this transition be implemented, given that current practice is to adjust all wind and solar resources’ ELCCs with each new ELCC study?
  

SCE, Calpine, and East Bay Community Energy (EBCE) co-chaired this working group.

Working Group

On February 13, 2020, a working group meeting was held where SCE presented a proposal to utilize a marginal ELCC for solar and wind resources for the lifetime of each resource and the applicable marginal ELCC for all capacity additions or repowering. In essence, through the use of the average ELCC, SCE argued that new renewable resources had their reliability values overstated at the expense of lowering the capacity value of existing resources. With the addition of resources with higher marginal capacity value, SCE also commented that existing renewables would have their ELCC values increased (i.e., resource diversity effect). AWEA and PG&E argued that this methodology would create issues since identical resources would have different capacity values, essentially triggering an uneven playing ground among resources, but SCE countered that the same outcome would occur, albeit later, under an average ELCC methodology. Other participants discussed approaches to grandfathering, repowering, and exploring opportunities to improve consistency between RPS and RA ELCC methodologies while balancing increased analytical complexity. Finally, SCE and SDG&E expressed concern with the known differences in the average ELCC methodology used for RA compliance and marginal ELCC methodology used for IOU RPS procurement.

Calpine presented on the need for applying the ELCC methodology to standalone energy storage assets, arguments that were grounded on the premise that the peaking capacity of energy storage is largely dependent on the penetration of storage in terms of peak load. Calpine argued that an ELCC methodology would better show the actual capacity contribution energy storage resources, particularly those with four-hour durations, but acknowledged that, currently, the ELCC of storage would be at or around 100%. CAISO agreed with Calpine, noting this is a growing concern for them since the dependence on energy- and use-limited resources has increased. CESA and others, however, agreed that this is not an urgent issue discussed the appropriateness of applying ELCC to storage and other energy-limited resources such as DR, the importance of modeling assumptions in the derivation of storage ELCCs, and the timing for consideration of a storage ELCC and associated commercial implications.

CESA recommended that the CPUC not adopt an ELCC-based framework for standalone storage resources at this time since any such modifications of standalone storage QC rules might prove financially disruptive and materially inconsequential at this time. If the CPUC decides to explore an ELCC methodology in the future, CESA urged the CPUC to set clear vintaging rules in place, evaluate ELCC for different energy storage durations, and perform ELCC analysis under a wide selection of renewable energy penetrations.

See CESA’s proposal on February 21, 2020 on Track 2 issues

On February 21, 2020, in Track 2 proposals, Form Energy proposed that look-up tables with marginal ELCC values for storage, wind, solar, and hybrids should be developed while abandoning MCC buckets, which lack transparency and do not adequately guard against energy insufficiency concerns.

On March 11, 2020, the co-chairs submitted the final report that summarized the working group discussions but did not identify any areas of consensus, thus leading to little actually accomplished or directed.

On June 30, 2020, D.20-06-031 was issued that found that there was insufficient consensus among parties to expand or revise the ELCC methodology at this time, though finding merit in Energy Division exploring ELCC differentiated by location and technology via studies. Fortunately, the decision also declined to adopt ELCC values for DR and storage resources at this time due to varying program rules and contractual obligations, thus rejecting the CAISO’s proposal. Despite some parties pushing for changes to marginal ELCC for solar/wind or a standalone ELCC for storage, the CPUC deferred on this issue, which CESA previously advocated as being premature at this time.

Energy Requirements

Background

On January 21, 2020, a Scoping Memo was issued that divided the proceeding into four tracks. Track 3 will address more complex and somewhat less time-sensitive structural changes and refinements to the RA Program, including examination of the broader RA capacity structure to address energy attributes and hourly capacity requirements given the increasing penetration of use-limited resources, among other factors.

Modified Portfolio Concept

CESA submitted a proposal to reframe the MCC paradigm to: (1) flexibly account for RA needs in the state rather than focus on unnecessary requirements for continuous dispatch by modifying the AAHs by bucket; and (2) apply the MCC framework for Local RA as well as System RA. While the emphasis on continuous dispatch is both unduly restrictive and unable to account for the actual ramping and capacity needs of California’s electric system, the MCC structure itself can serve as a vehicle towards a more sophisticated portfolio-based RA program. This proposal would enable resources to be procured to work in a “block stacking” fashion based on the timing of different system capacity needs. In addition, the RA Program should use the net load duration curve instead of the gross load duration curve, where solar and wind, regardless of their point of interconnection, will be attributed RA-reducing value as opposed to supply-side RA value. Separately, CESA also recommended that the CPUC unbundle all RA attributes to allow for efficient procurement and targeted availability and evaluate the various elements of RA (e.g., UCAP, energy) for transactability. Bundling of RA products has the potential to increase contracting costs as it makes it impossible for LSEs to procure solely the attribute in which it is deficient (e.g., Local RA).

See CESA’s proposal on August 7, 2020 on Track 3B Scoping Memo Issues

Flexible RA Reform (R.17-09-020)

Flex Down RA, Fast Flexibility, & Unbundling

On February 16, 2018, CESA also submitted a Track 1 proposal that recommended the following reforms to the RA program to ensure that the state’s fleet can meet the grid needs:

• The RA planning tool should ensure sufficient capacity (with participation obligations) for downward ramping flexibility – i.e., a ‘Flex RA Down’ product.

• Track 2 of the proceeding should explicitly authorize and unbundle Flexible RA from System or Local RA attributes so that flexibility-focused resources can be designed and interconnected without needing or planning for other RA duties and peak deliverability, benefiting ratepayers.

• Resources that have modest transition times to go from charging to discharging should be authorized for Flexible RA value that ranges from the appropriately determined Pmax to the appropriately determined Pmin.

On February 22-23, 2018, a workshop was held on Track 1 proposals submitted by parties. A wide range of ideas was proposed and presented at the workshop. To address flexibility issues in operating the grid today and in the future, Cogentrix and Wellhead Electric proposed variations of a Fast Flex RA sub-product that would tighten the current over-inclusive Flex RA product. Both parties highlighted several key attributes of such a product including startup and ramp time, minimum starts and ramps per day, minimum uptimes, sustained operations at Pmax, and quick ramp down to non-generating condition. Cogentrix focused particularly on the need for an interim product until the CAISO and CPUC develop a permanent solution. CESA reiterated support for proposals that improves and enhances the Flex RA product, unbundles System and Flex RA, and authorizes RA counting for hybrid storage resources.

See CESA's comments on March 7, 2018 on the Track 1 proposals workshop.

On May 22, 2018, a PD was issued. CESA supported the PD on our narrow issue. While appreciative of this clarification, CESA commented that the RA proceeding should continue to work on valuing the capacity and flexibility benefits of hybrid energy storage configurations, with the goal of emphasizing the importance of ELCC reforms for Track 2. The major focus of disappointment in comments came from WPTF and the IPP community because the PD deferred adjustments to the ELCC methodology to account for BTM solar PV as supply-side resources, which WPTF views as under-counting RA requirements. The CPUC cited the need for further study. Previously, in a 2017 decision, the CPUC also deferred this issue to provide a smoother glidepath to ELCC value updates for solar and wind.

See CESA's comments on June 11, 2018 on the Track 1 Proposed Decision.

On June 25, 2018, D.18-06-030 was issued that approved the PD with only minor clarifications and modifications. The key takeaway from this decision was that the CPUC is concerned about how load migration has been impacting (and will continue to increasingly affect) resource planning for reliability, as CCA expansion continues to grow and needed generators face retirements (with the decision even highlighting two such resources in Ellwood and Ormond Beach). There were a number of proposals that were also rejected, including PG&E’s monthly Local & Flex RA requirements. PG&E proposed to adjust Local/Flex RA requirements on monthly basis (similar to what is done for System RA), but the decision concluded that this may be too burdensome for CPUC staff to manage and added that CCA participation in the year-ahead process would sufficiently mitigate any month-by-month deficiencies for Local and Flex RA resources. The other issues that were deferred to Track 2 due to limited record development or policy development needed in other policy venues included Flex RA reforms (e.g., Fast Flex RA, Flex Down RA) and System RA requirement changes for shoulder months.

In sum, CESA’s core issues around developing new Fast Flex RA and Flex RA Down products were pushed to Track 2 to address these shorter-term issues that are pressing and important to the CPUC. The role of preferred resources like energy storage in addressing forward capacity needs is also being elevated in the discussions around the multi-year RA framework and the solutions to avoid backstop procurement. Separately, in the TPP, the CAISO will conduct a special study to proactively identify potential economic local capacity requirement reductions through transmission and preferred resource alternatives.

On July 10, 2018, opening testimony for Track 2 proposals were served by more than 20 parties. CESA submitted its testimony as well that focused on three conceptual proposals for consideration in Track 2:

• Flexible RA should be unbundled from System or Local RA attributes so that flexibility-focused resources can be designed and interconnected without needing or planning for other RA duties and peak deliverability, benefiting ratepayers.

• Fast flexibility should be valued – the long-standing three-hour ‘standard’ should be updated, or the CAISO's proposals in the FRACMOO Initiative to productize flexibility as day-ahead, 15-minute, and 5-minute flexible capacity products should be adopted.

• 'Downward flexibility' capability planning is warranted but this issue could be addressed in Track 3.

See CESA's testimony on July 10, 2018 on Track 2 Proposals.

On August 8, 2018, CESA offered the following (more procedural) recommendations as well as some responses to testimony served by other parties. In particular, CESA recommended that workshops be held to discuss the unbundling of Flexible RA from System/Local RA.

See CESA's comments on August 8, 2018 on the E-Mail Ruling

On July 5, 2019, D.19-06-026 was issued that did not address Flex RA or unbundling issues. CESA offered comments reiterating its importance.

Storage EFC Modifications

On June 30, 2020, D.20-06-031 was issued that CPUC that modified the current EFC methodology that is calculated as the greater of the NQC value or the difference of NQC and PminRA, which is defined as the height of a rectangle where the base is 1.5 hours of discharge and the area is the battery’s available energy for dispatch in MWh. Instead, the decision capped both the PminRA and PmaxRA at the QC value of a 4-hour dispatch, which would equate to an EFC value of twice the QC value.

• If Psupplymin and Psupplymax = 0, then EFC = PmaxRA – PminRA

• If Psupplymin and Psupplymax ≠ 0, then EFC = (PmaxRA – Psupplymin) – PminRA – Pdemandmin)

Psupplymin is a positive number representing the minimum amount of discharging or load curtailment that is sustainable for three or more consecutive hours. Pdemandmin is a negative number representing the smallest magnitude of charging or load increase that is sustainable for the duration required in calculating EFC. CESA appreciated the clean-up of the EFC counting for storage, which were previously capped on the negative generation side of the flexibility that storage could provide. CESA supported the CPUC’s adoption of the modifications proposed to the calculation of the effective flexible capacity of energy storage resources.

See CESA’s comments on June 11, 2020 on the Proposed Decision

Hybrid Storage Capacity

Background

On January 21, 2020, a Scoping Memo was issued that divided the proceeding into four tracks. Track 2 will consider qualifying capacity (QC) counting conventions and requirements for hybrid resources and address the following question: "Should the CPUC adopt a permanent methodology for counting of hybrid resources?" CESA co-chaired the working group along with SDG&E.

Hybrid/Co-Located Resource Capacity with 100% Charging from Onsite Generation

On June 30, 2020, D.20-06-031 was issued that adopted the consensus proposals from the Track 2 Hybrid QC Working Group. For hybrid and co-located resources, the CPUC adopted definitions similar to those used by CAISO:

• Hybrid resource is “two or more resources (one of which is a storage project) located at a single point of interconnection with a single resource ID.”

• Co-located resources are “two or more resources (one of which is a storage project) located at a single point of interconnection with two or more resource IDs.”

SCE’s proposal was adopted for any hybrid and co-located resource that will charge entirely from the paired renewable generator. For each month, Energy Division is directed to create an energy profile to determine the average number of hours available to charge the storage device from two hours after net load peak until two hours before net load peak. The QC value of the renewable component shall be determined by applying the ELCC percentage to the difference between the renewable’s nameplate capacity and the capacity needed to charge the battery at a constant rate over the available charging hours. The QC of the battery component shall be based on the renewable charging energy transferred to the battery in the allotted time period divided by four. The following equation will be used: Total QC = Effective ES QC + Effective Renewable QC, capped at the point of interconnection limit, where:

• Effective ES QC equals the minimum of: (1) the energy (MWh) production from the renewable resource until 2 hours before the net load peak assuming charging is done at a rate less than or equal to the energy storage’s capacity, which is then divided by 4 hours to determine the QC; or (2) the QC of the energy storage device.

• Effective Renewable QC equals the remaining renewable capacity, net of the capacity required to charge the battery (i.e., Effective ES QC) at a constant rate over the available charging hours, multiplied by the ELCC factor for the month.

However, the decision declined to adopt any proposals at this time for ITC Limited charging (75%-99% onsite) and non-ITC Limited scenarios due to the lack of clarity on how it will respond to must-offer obligations. In addition, at this time, the CPUC deemed consideration of specific treatment of BTM resources as premature until broader questions and existing barriers can be been addressed.

While not the comprehensive solution, the pathway for hybrid and co-located resources represent an incremental improvement that recognizes the most prevalent current use case (100% ITC charging) but still requires work on non-100% cases and for what applies after the 5-year ITC recapture period. For resources without actual generation data, it is unclear on how Energy Division will generate the profiles to apply this adopted QC methodology. However, a major area of concern is the decision’s explanation of NEM and SGIP as already compensating for capacity, which we view to be a premature determination made without discussion in the RA proceeding or consideration of incrementality principles and policies adopted in other proceedings (such as the ones focused on distribution planning, R.14-08-013, R.14-10-010). Since findings, conclusions, or orders were not made in light of this explanation, CESA opted against any rehearing or appeal process but will instead focus on scoping a new cross-cutting proceeding focused on Multiple-Use Applications (MUAs).

CESA supported the PD’s adoption of SCE’s proposal but recommended that, consistent with the original vision of SCE, project-specific energy profiles should be used in implementing the hybrid and co-located capacity counting methodology. In addition, different hybrid and co-located use-cases and configurations should be examined in Track 3 of this proceeding to develop a comprehensive capacity counting framework. In response, the PD was revised to clarify that Energy Division will utilize actual generation data from the CAISO that is obtained through subpoenas for the time being, with a working group in the future to address whether any further modifications are necessary. However, this seemingly only works for existing solar resources adding paired storage capacity; for new solar-plus-storage project builds without actual generation data, the decision does not address how these profiles will be generated and thus have their QC value determined.

Meanwhile, we recommended that a Working Group should be established in Track 3 to provide focus on the barriers and solutions related to RA valuation of BTM energy storage and hybrid resources. In response, the PD was revised to express interest in the possibility of increasing value for BTM hybrid resources and directed a joint-agency workshop to be held to plan the steps necessary to establish NQC values for hybrid BTM storage and solar resources. However, the PD was also revised to declare that NEM and SGIP resources are already compensated for capacity and should only be given RA compensation that is incremental and discounted from assumed NEM/SGIP value.

See CESA’s comments on June 11, 2020 on the Proposed Decision

CESA submitted a proposal that different hybrid and co-located use-cases and configurations should be examined in Track 3B to develop a comprehensive capacity counting framework.

See CESA’s proposal on August 7, 2020 on Track 3B Scoping Memo Issues

Working Group

On September 5-6, 2019, CPUC held working group meetings on several topics including local RA requirements, market power/system waivers, counting methodologies for hydro and use-limited fossil resources, ELCC methodologies, and counting methodologies for combined resources. CESA presented at this workshop regarding our preliminary, directional modeling results for ELCC values of different combinations of solar and storage resources.

The CPUC Energy Division recommended an exceedance methodology for single Resource ID configurations, expressing concerns that renewable generation does not separately provide RA capacity when renewable generation must charge storage. An exceedance methodology would determine the MW output met or exceeded in 70% of the “target” hours. However, the CPUC recognized that average ELCC calculations cannot work for hybrid configurations due to the range of potential configurations – i.e., a case-by-case method like exceedance is needed. However, there are challenges to using exceedance since it focuses only on the availability assessment hours (not all hours of the market) and relies on historical data (36 months). Some of the key discussion questions included:

• Would ELCC value hybrid resources more accurately than exceedance? Why or why not?

• How would we model resources that have similar storage-to-generation ratios but operate differently?

• Would solar-plus-storage resources that receive the ITC (solar charges storage greater than or equal to 75% of the time) also have separate CAISO resource IDs? If so, how would we value these resources?

• Could hybrid resources discharge at this 70% value for four consecutive hours (to avoid RAAIM penalties)?

• Should parties file formal or informal comments?

• What topics are higher priorities?

• Should negative adjustments from 100% ELCC resources be allocated or just positive diversity adjustments?

• How should we prorate diversity benefit to all resources that have ELCC under 100%?

• Ought we perform full ELCC studies for storage? Two and four hour storage buckets?

Meanwhile, the CAISO and SCE supported similar proposals to use an additive approach for hybrid resources with a single Resource ID, subject to deliverability and interconnection capacity rights. The CAISO, in particular, supported this as an interim methodology until a more nuanced approach can be developed to support near-term reliability needs in 2021, where storage retrofits to existing solar facilities via the material modification process could support expedited deployment of capacity resources. The CAISO indicated that it would attempt to provide some fast tracking to interconnect new resources. However, to ensure that the storage retrofits are charged to serve net load peak, the CAISO said it will explore the use of exceptional dispatch or requirement for storage resource self-scheduling, though this may limit the full flexibility of storage resources. The CPUC staff is also looking for feedback on ELCC studies that their modeling team could conduct, where there may be limitations in time and resources around the number of parameters to model among location, technology, annual/monthly, etc.

On February 12, 2020, a working group meeting was held to discuss proposals related to hybrid and co-located resource QC methodologies. CESA co-chaired the working group and presented a holistic approach to determine the QC value of hybrid resources where any permanent methodology must take into account: (1) the market participation pathway of the hybrid resource; (2) ITC-related charging; and, (3) the storage-to-generation ratio. CESA proposed a framework that captures the nuances related to charging, market participation, and operational tradeoffs in order to inform the development of a permanent QC methodology for hybrid resources. CESA proposed distinct methodologies for assets operated under: (a) the generator model; (b) the NGR model with a low storage-to-generation ratio; and, (c) the NGR model with a high storage-to-generation ratio. For some of these scenarios CESA proposed the creation of derating formulae and the application of an additive approach for the resulting underlying capacity values. For model (a), CESA proposed a derating of the capacity value of on-site generation (i.e., ELCC) and the use of an additive approach, capped at the POI. For model (b), CESA proposed the application of an additive methodology, capped at the POI. For case (c), CESA proposed a derating of the storage’s NQC and the use of an additive approach, capped at the POI.

SCE presented a framework for renewable hybrids only charged from the onsite generation based on: (1) effective energy storage QC calculated from the minimum of the energy production from the renewable resource until two hours before the net peak load assuming charging is done at a rate less than or equal to the storage’s capacity, or the QC of the storage facility; and (2) the effective solar QC calculated from the remaining solar capacity, net of the capacity required to charge the battery, multiplied by the ELCC factor for the month.

Other parties also presented proposals:

• SDG&E recommended that the CPUC wait until the IOUs complete their ELCC study on renewable resources paired with one- and two-hour storage by October 1, 2020, which will promote consistency and more accurate methodologies.

• SEIA and LSA proposed that the permanent RA counting method for hybrid solar resources should move to the use of the additive method, where the RA value is the sum of the NQCs of the individual co-located solar and storage units. SEIA and LSA presented analysis exploring whether any constraints on the additive method might be needed as a result of resource configuration, ratio of storage to renewable capacity, or storage duration. Their analysis finds that the Additive Method may need to be limited only: (1) by the size of the single inverter in DC-coupled configurations; or (2) in winter months for systems where the discharge capacity for four-hour storage is greater than 75% of the solar nameplate. Finally, it is important to note that hybrid resource owners have the ability to use up to 25% grid power to fill storage (with some loss of the ITC), so the hybrid owner can make an economic decision whether to supply RA up to the full Additive Method in winter month

• Sunrun proposed that BTM hybrid resources have a QC value to be the same as for IFOM hybrid resources initially based on full resource output and applicable only to those under contract or other obligation to provide capacity to an LSE.

CESA proposed that the CPUC adopt a comprehensive framework to value the capacity of hybrid resources that properly reflect their configurations, incentives, capabilities, and market participation approaches. CESA argued that any permanent QC methodology for hybrid resources must take into account: (1) the market participation pathway of the hybrid resource (generator versus NGR models); (2) the storage-to-generation ratio; (3) ITC charging incentives; and (4) the inverter size at the POI.  As such, CESA proposed distinct methodologies for assets operated under: (a) the generator model and the NGR model that intend to claim full ITC incentives; (b) the NGR model with a low storage-to-generation ratio; and (c) the NGR model with a high storage-to-generation ratio and intent to claim partial ITC incentives.  For some of these scenarios, CESA proposed the creation of derating formulas and the application of an additive approach for the resulting underlying capacity values.

See CESA’s proposal on February 21, 2020 on Track 2 Issues

On February 24, 2020, a second working group meeting was held where CAISO began with a presentation on the importance of aligning CPUC and CAISO definitions that must account for market participation models (e.g., net-to-grid output submitted by scheduling coordinator), while stating that the greater-of and additive methodologies do not ensure assigned reliability value will be realized in actual operations of hybrid resources with ITC charging restrictions. As a result, the CAISO reverted back to the position that the exceedance methodology should be used for hybrid resources with past actual production data of hybrid resources over a 5am-9pm window to inform reasonable expectations and reliability contributions in the future. Until historical production data is produced, an additive approach could be used for one or two years. For co-located resources, the ELCC could continue to be used for solar and wind but an exceedance approach for storage could be applied and assessed for the 4pm-9pm AAH window.

Meanwhile, due to must-offer obligation challenges for partial grid charging cases, participants seemed to generally agree that the 100% ITC charging case was the most straightforward and could leverage some combination of the proposals of SCE, CESA, and SEIA/LSA, which shared a number of commonalities. SCE believed that its proposal would not distinguish between hybrid and co-located resources since ITC charging is a use limitation.

On March 11, 2020, CESA and SDG&E submitted the final report from this working group. CESA recommended that the consensus definitions for hybrid and co-located resource variations in the working group report should be adopted but modified to cover the scope of projects that are not physically limited and can optimize for economic value and deliver further benefits. While SCE’s proposal represents a viable consensus methodology to address the 100% ITC-limited case, further follow-up working groups are needed to address the other identified use cases. Additionally, the appropriateness and details of the exceedance methodology needs to be further explored and vetted prior to use for paired resources, and hybrid resources without charging restrictions should be counted using an additive methodology.

See CESA’s comments on March 23, 2020 and reply comments on April 2, 2020 on the Working Group Report

Additionally, CESA joined CEERT and SCE in support of SCE’s additive methodology for 100% ITC-limited co-located resources in a show of unified support to replace the interim greater-of methodology.

See CESA’s joint comments on March 23, 2020 on the Working Group Report

Interim 2020 Conservative "Greater-of" Methodology

On November 26, 2019, a PD was issued that grants, with modifications, the motion to establish a schedule and process for determining the QC value of hybrid resources. The CPUC was compelled by the need to establish an interim QC methodology to support valuations in competitive solicitations in response to the IRP’s 3,300 MW reliability procurement requirement. In line with the CAISO, the CPUC proposes to adopt a hybrid resource definition as generating resources co-located with storage resources under a single Resource ID. Specifically, for hybrid resources with operational restrictions, the PD adopted SDG&E’s proposed interim solution to set the QC value based on the greater of either: (i) the ELCC-based QC of the intermittent resource or the QC of the dispatchable resource, whichever applies; or (ii) the QC of the co-located storage device. While recognizing that this interim solution may under-value the QC of hybrid resources, the CPUC implied that over-valuing the QC of hybrid resources using SCE’s additive approach may risk reliability, considering the motion was granted in large part due to the IRP procurement decision. The PD found it unnecessary to adopt a QC value for hybrid resources without operational restrictions and deemed it premature to establish QC values for BTM resources at this time.

CESA was encouraged to see the CPUC adopt an interim solution to support valuation of plus-storage resources in the number of IRP-related competitive solicitations. This PD would encourage storage retrofits and new plus-storage hybrid resource development by crediting LSEs with additional capacity value in procuring such resources. CESA was supportive of the CPUC’s timely actions on setting an interim capacity value methodology but offered the following recommendations:

• The CPUC should properly and clearly define “operational restrictions” and distinguish how not all hybrid resources have operational restrictions. The PD considers does not provide a clear definition of “operational restrictions”; instead, it merely alludes to “charging restrictions and others” as examples of said restrictions. In order to provide certainty and transparency, the CPUC should clarify what qualifies as an operational restriction in a detailed manner.

• The CPUC should recognize the different operational structures available for hybrid resources in CAISO’s markets. Currently, the PD does not reflect the differences by which hybrid resources can participate as generators or NGRs. Such categories provide developers with options and determine the asset’s metering requirements, market participation models, and forecasting needs.

• The CPUC should consider all hybrid configurations and adopt an additive methodology as the interim qualifying capacity methodology. As proposed, the PD appears to narrowly focus on hybrid resources consisting of a variable energy resource (VER) paired with an energy storage asset that is sized in order to provide energy shifting benefits. CESA believes this limited scope fails to capture the nuances and benefits associated with other hybrid configurations; for example, VERs coupled with small additions of storage for generation firming, and hybrid gas-storage designs.

• The CPUC should consider establishing a QC methodology for BTM hybrid resources. CESA urges the CPUC to provide guidance regarding the capacity values for BTM hybrid resources, especially in light of recent PSPS events.

Several parties submitted opening comments, with the IOUs, Public Advocates Office (PAO), CAISO, and Calpine generally in support of the PD despite some recommended clarifications to the definition of “operational restrictions” and the use of monthly as opposed to annual QC values. PG&E and SCE also agreed that the interim methodology should only apply to IFOM hybrid resources at this time since BTM hybrid resources raise jurisdictional questions that are better addressed in R.19-11-009. SCE in particular offered additional refinements that would define hybrid resources as those including any partial or full charging restriction as well as a modified QC value for the paired storage resource that would be capped at the maximum amount of energy available for charging, thus accounting for circumstances where the storage facility is sized above the amount of energy that is likely to be stored in order to support the QC. Specifically, for a solar- or wind-plus-storage hybrid resource, the modified QC for the storage device should be calculated as the maximum capacity of the solar resource (Pmax) multiplied by the capacity factor (30% for solar, 33% for wind) times 24 hours and divided by four, leading to a modified QC of the storage as 1.8 times Pmax of the solar resource or 1.98 times Pmax of the wind resource. The final QC value for the storage component of the hybrid resource would then be set as the lesser of the modified QC, as calculated above, or the QC of the storage device as if it were a stand-alone device.

CESA reiterated our recommendation that the CPUC should adopt an additive interim methodology as it aligns with California’s policy goals and the CAISO’s Hybrid Resources Framework. However, if the Commission decides to adopt a “greater-of” methodology, it should define “operational restrictions” as storage assets charging exclusively from the paired generation resource and should clarify that the proposed interim methodology would only apply for resources with “operational restriction” as defined. Meanwhile, CESA recommended against adopting SCE’s modified QC methodology for hybrid resources with oversized storage components, which further depresses the capacity value of hybrids and inappropriately makes assumptions of charging restrictions exclusively to the paired generating facility. Finally, CESA recommended that the CPUC start a working group process to define a permanent capacity-counting methodology for hybrid resources.

See CESA’s comments and joint party comments on December 20, 2019 and reply comments on January 2, 2020

On January 17, 2020, D.20-01-004 was issued that made the following key revisions from the original PD:

• Greater-of methodology: The revised PD affirmed the greater-of methodology as being appropriately conservative at this time.

• Definition of operational restrictions: In response to comments, including those from CESA, the PD was modified to clarify how the interim methodology would only apply to a hybrid resource with ITC-related charging restrictions, regardless of whether the resource operates under a single or multiple resource IDs.

• Monthly QC values: In response to SDG&E’s comments, the PD was modified to differentiate the QC value of the storage device by month since the ELCC-based QC value of intermittent renewable resources vary by month as well.

• Oversized storage components: In response to SCE’s comments, the PD was modified to cap the monthly QC of the battery to the amount of energy that can reasonably be expected to be available to charge the storage device on a daily basis.

• BTM hybrid resources: The PD clarified that a QC methodology for BTM hybrid resources is premature at this time, noting that BTM storage cannot export as demand response resources and thus are fairly credited using proxy demand resource approaches. The revised PD added that BTM storage that can export are already compensated through NEM and do not have telemetry to allow for CAISO dispatch and/or performance-based compensation.

Overall, CESA was extremely disappointed with the non-revisions made in the PD to adopt an additive methodology, which would have likely captured many different hybrid resource configurations, even though it could reasonably be argued that such a methodology could overstate the capacity contributions of such resources. Furthermore, the extension of the greater-of methodology to all plus-storage resources with ITC-related constraints represented a significant (worse) change for co-located resources with two resource IDs. While the definition of operational restrictions was slightly clearer, it assumed the same “effects” on the capacity value with the greater-of methodology. Finally, CESA was unclear on how the “cap” on storage monthly QC values would be applied – i.e., whether the CAISO, LSE, or CPUC staff would be the one that ultimately determines “reasonable expectation” to charge the storage device on a daily basis.

On February 11, 2020, the Joint Parties (CESA, AWEA, CEERT, and Enel X North America) submitted a PFM that requested that the CPUC expeditiously adopt a revision to the definition of “hybrid resource” as a generating resource co-located with a storage project and with a single point of interconnection and represented by a single market resource ID, so that the interim greater-of QC methodology does not applied to co-located generation and storage resources operating under two or more resource IDs. The requested modification was justified on the following grounds:

• The CPUC’s application of the interim greater-of methodology to co-located resources is not grounded in the public record and is thus procedurally deficient.

• The inclusion of co-located resources in the hybrid resources definition is at odds with the market participation realities of co-located resources in the CAISO market.

• Unless modified, D.20-01-004 would increase ratepayer costs and counteract efforts to advance the state’s decarbonization goals at reasonable costs for procurement conducted pursuant to D.19-11-016.

• Appropriate scope and timely adoption of an interim methodology for hybrid, not co-located, resources are needed to provide procurement certainty as stakeholders work through potentially complex issues in establishing a permanent methodology.

In response, the solar parties supported the PFM and cited an example of a storage retrofit that would receive little or no QC value as a co-located resource. PG&E and SCE dismissed the procedural claims since R.19-11-009 will consider a permanent methodology. Notably, CAISO agreed with the need to refine the definition of “hybrid resources” to those as a single resource with a single resource ID while establishing an additive QC methodology on an interim basis for co-located resources with more than one resource ID until it transitions to an exceedance methodology.

On September 16, 2020, D.20-09-003 was issued that denied multiple PFMs and closed the R.17-09-020 proceeding. Specifically, the PD denied the Joint Parties’ PFM of D.20-01-004 that proposed a hybrid and co-located resource definitions in line with that of the CAISO and the application of an additive definition for co-located resources. Since D.20-06-031 made the appropriate definition changes and adopted an effective additive methodology for 100% ITC-limited hybrid and co-located resources, the PD found this PFM to be moot.

D.20-06-031 did address QC value methodologies for 100% ITC-limited hybrid and co-located resources, but the CPUC has not yet adopted a methodology for all other use cases discussed in the Hybrid QC Working Group Report, including 75%-99% ITC-limited use case and the disputed non-ITC-limited use case. CESA was supportive of D.20-06-031 and thus found no major issue with the PD dismissing CESA’s PFM filed jointly with other parties. However, some additional clarifications may be needed on other use cases. For example, it is unclear at this time whether the interim greater-or or effective additive methodology will apply if storage is committed to charge at any level below 100% while claiming the ITC.  

See CESA’s comments on August 24, 2020 on the Proposed Decision

ELCC Impacts of Paired Storage (Track 1-3 of R.17-09-020)

On February 16, 2018, CESA also submitted a Track 1 proposal that recommended that combinations of of energy storage and demand response should be authorized to provide combined RA service via a revision to D.14-06-050.

On February 22-23, 2018, a workshop was held on Track 1 proposals submitted by parties. A wide range of ideas was proposed and presented at the workshop. SCE and WPTF proposed treating IFOM and BTM solar the same as supply resources in the ELCC calculation to avoid overestimating solar’s ELCC value. SCE also advocated for using marginal ELCC for RA purposes, but with average ELCC being used for Renewables Portfolio Standard (RPS) resources for RA today, SCE claims these resources are being overvalued. SCE also supported ELCC differences that account for location and technology.

The unplanned generation retirement issue and CCA migration are key issues that might dominate mind share early on, leading to CESA’s issues to mostly likely be considered later in Track 2. CESA reiterated support for proposals that improves and enhances the Flex RA product, unbundles System and Flex RA, and authorizes RA counting for hybrid storage resources.

See CESA's comments on March 7, 2018 on the Track 1 proposals workshop

On May 22, 2018, a PD was issued that focused on multi-year and central buyer framework issues. CESA supported the PD on our narrow issue. While appreciative of this clarification, CESA commented that the RA proceeding should continue to work on valuing the capacity and flexibility benefits of hybrid energy storage configurations, with the goal of emphasizing the importance of ELCC reforms for Track 2. The major focus of disappointment in comments came from WPTF and the IPP community because the PD deferred adjustments to the ELCC methodology to account for BTM solar PV as supply-side resources, which WPTF views as under-counting RA requirements. The CPUC cited the need for further study. Previously, in a 2017 decision, the CPUC also deferred this issue to provide a smoother glidepath to ELCC value updates for solar and wind.

See CESA's comments on June 11, 2018 on the Track 1 Proposed Decision

On June 25, 2018, D.18-06-030 was issued that approved the PD with only minor clarifications and modifications, but there were several other smaller changes approved in the decision. CESA did secure a minor clarification in the decision that will allow for hybrid energy storage and DR resources to qualify for RA. The decision removed a prohibition from a previous decision (D.14-06-050) that prevented energy storage resources from being combined with DR resources in an aggregation to provide RA. This was a minor clarification that many stakeholders were unaware was in place, but this clarification will be key to enabling unique hybrid BTM aggregations. No parties were opposed to this determination, but the CAISO, PG&E, SCE, and CEERT noted that more work is needed to determine the qualifying capacity value of combined resources. The other issues that were deferred to Track 2 due to limited record development or policy development needed in other policy venues, including ELCC reforms (e.g., inclusion of BTM PV, locational/technological differences, marginal versus average ELCC).

In sum, CESA’s core issues around ELCC boosts for solar and wind resources paired with energy storage were pushed to Track 2 to address these shorter-term issues that are pressing and important to the CPUC. The role of preferred resources like energy storage in addressing forward capacity needs is also being elevated in the discussions around the multi-year RA framework and the solutions to avoid backstop procurement.

On July 10, 2018, opening testimony for Track 2 proposals were served by more than 20 parties. CESA focused on the need for an ELCC methodology for energy storage resources paired with solar or wind resources to be established, and how CESA will endeavor to provide a methodology for consideration.

See CESA's testimony on July 10, 2018 on Track 2 Proposals.

On August 8, 2018, CESA offered the following (more procedural) recommendations as well as some responses to testimony served by other parties. Specifically, a technical working group should be formed to modify the ELCC methodology for hybrid energy storage resources. In addition, the full charge to discharge range should be credited for standalone and hybrid energy storage resources and should be affirmed by the CPUC.

See CESA's comments on August 8, 2018 on the E-Mail Ruling

On March 4, 2019, D.19-02-022 was issued that adopted requirements for implementation of a multi-year Local RA procurement to begin for the 2020 RA compliance year but importantly punted on adopting a central buyer structure. ELCC issues were not addressed.

In sum, CESA found the decision’s reduction of the Year 3 forward procurement requirement (from 80% in the PD to 50% in the final decision) to be positive for potential new energy storage procurement. The adopted requirements therefore provide some stability in the near term for existing gas generators needed for local reliability but also opens up more opportunity for greater competition in Year 3. The decision cited and agreed with CESA’s and other parties’ comments on the PD on this matter, so this is a positive incremental win.

On February 13, 2019, a Ruling was issued that attached an updated staff presentation on the ELCC studies for each standalone resource (wind, solar, and  energy storage, which includes batteries and pumped storage) and for the total portfolio of wind, solar, and storage. These four study results may be used to establish RA capacity counting rules for wind and solar generators, not storage, in the 2020 RA compliance year. The key update in this proposal was that the CPUC staff simply allocated the ‘diversity benefit’ to wind and solar, with none allocated to storage, which has an ELCC capped at 100%. Most of the diversity benefit of energy storage was allocated to supply-side solar as solar is the chief driver of overgeneration that is used to charge storage. These studies were conducted as part of the staff’s proposal in February 2018 to examine the diversity benefit of portfolios and individual classes of non-dispatchable resources, which took an approach to reallocate the perfect MW capacity (PCap) equivalent of one resource class to other resource classes to calculate the final diversity-adjusted ELCC percentage. The CPUC staff explained that the diversity benefit of solar and wind can occur by covering LOLE events that any individual resource class could not cover. This diversity benefit varies by month of the year. Based on the below results, it is clear that the ELCC effects of storage are greatest in the spring, with some significant effects in the summer as well.

While posing questions for stakeholders to comment, the CPUC staff proposed to allocate all excess ELCC value from storage to solar because energy storage dispatch followed charging during periods of solar overgeneration, which would give energy storage an NQC value of 100%. Importantly, staff’s proposal would have the effect of lowering the monthly ELCC value of wind in the summer months and reduce the monthly ELCC value of solar across most months. Together, the studies show tremendous value in procuring storage along with renewables.

CESA supported the proposal and focused on the following points and recommendations:

• For the 2020 RA year, the CPUC should authorize ELCC counts for solar-plus-storage and other plus-storage, which are needed and are doable today.

• SCE’s proposals for Net Qualifying Capacity (NQC), Effective Flexible Capacity (EFC), and non-dispatchable generating resource plus storage are reasonable and should be authorized immediately.

• The CPUC Staff Proposal to update solar and wind ELCC values should be a one-time allocation but it should not be precedential to socialize the ELCC benefits from new storage added to solar, wind, or other plants to a category of resources.

• For the 2020 RA year, the CPUC should immediately recount EFC based on the ramp range that can be achieved in 15 minutes, rather than 3 hours.

• The CPUC should unbundle Flex and System attributes for the 2020 RA year and should support CAISO flex-only deliverability studies.

• The CPUC should have a two-day forum on the overall concepts and goals of RA as a tool in the future grid mix.

• The CPUC should have a one-day workshop to consider the roles, rules, and potential issues for DERs to support capacity needs, and to be contracted for such needs where appropriate.

• A discussion should occur around the planning reserve margin for flexibility and the conservative 1-in-2 planning scenarios.

See CESA’s comments on March 22, 2019 on the Ruling.

Other parties also filed comments on the diversity ELCC study. LS Power discussed how it is an oversimplification to assume energy storage charging during the mid-day and discharging during peak periods, given the CAISO's real-time optimization. Rather than allocating the entire excess 100% ELCC of storage to solar, LS Power recommended that this be assigned to the EFC of the resources. WPTF alternatively proposed that the excess ELCC benefits of storage be assigned on a pro rata basis to solar and wind resources. On the actual ELCC study, WPTF and PG&E recommended that the study treat BTM PV as supply-side resources to get a more accurate diversity benefit value, while TURN recommended that the Helms storage facility be included in the study, which would have lowered the storage ELCC value. 

On May 24, 2019, a PD was issued that addressed QC and ELCC methodologies for combined resources. The PD recognized as being important to clarify and modify but ultimately found these issues to be unnecessary to resolve (e.g., dispatchable generation plus storage) or impractical at this time (e.g., non-dispatchable renewables plus storage) given the need to model or consider many combinations of plus-storage resources. In addition, the PD declined to apply ELCC calculations for BTM PV at this time but implicitly calculated and adopted ELCC values that reflect the effect of BTM PV, leading to an overall decline in solar ELCC values compared to what was adopted in 2017 in D.17-06-027. However, the PD affirmed the allocation of the ELCC diversity benefit of storage (i.e., where storage ELCC value exceeded 100%) to any resources given the interaction effects of solar and storage from the CPUC staff’s modeling. A working group is directed to evaluate QC proposals and ELCC methodologies for renewables-plus-storage, as well as for PG&E’s proposal to differentiate compliance QC versus operational QC for hydro generation and use-limited fossil-fueled resources.

On these matters, the PD was disappointing in not making changes to QC or ELCC methodologies for combined resources, especially around allocating the diversity benefit of storage to other resources (i.e., solar) on an interim basis and around developing QC and ELCC values or calculators for plus-storage resources. These issues are punted for further discussion. As a result, standalone solar resources face reduced ELCC values as IFOM solar is modeled independent of BTM solar and LSEs are not given an economic signal to procure plus-storage resources.

CESA expressed our disappointment with the non-action around solar and wind ELCC calculations, especially regarding SCE's QC proposals for combined resources, which should take effect immediately. The working group established to discuss these matters should be convened as soon as possible to develop and implement proposals, such as those of CESA and SCE, among others. CESA also added some minor comments on the need to have QC/ELCC methodologies for combined resources with a single Resource ID as well as on how alternative methodologies (other than load impact protocols) may ultimately be adopted for DR-plus-storage resources via mechanisms such as the Demand Response Auction Mechanism (DRAM). The non-action on unbundling of System and Flexible attributes, other Flexible RA reforms, and consideration of DERs for RA counting also continues to be a concern and should be addressed as the next major scoping items.

Almost every party supported the newly adopted ELCC values for IFOM solar that removed the BTM solar effect, but many, including the CAISO, disagreed with the allocation of storage’s ELCC diversity benefit to a single class of resources (IFOM solar), as opposed to other resource types. The CAISO in particular criticized the ELCC study’s use of a 3-in-10-year LOLE that focused on high-load months instead of the industry standard 1-in-10-year LOLE and commented on the need to look at the operational capabilities of different storage technologies. As done in the ESDER Phase 4 Initiative, the CAISO also advocated for an ELCC methodology for DR resources. PG&E and SCE supported the PD’s ELCC diversity allocation approach even while recognizing the limitations, which should be studied further, but also commented on how storage capacity may be overstated as a result.  Finally, many parties such as PG&E, SDG&E, and Sunrun supported ELCC studies for BTM solar, with Sunrun advocating for ELCC capacity values to be set for BTM solar and BTM solar-plus-storage resources as well.

In response to other parties’ comments, CESA echoed the CAISO’s comments on how the ELCC methodology must account for different combined resources and storage technologies and rebutted comments by PG&E and SCE arguing in favor of lowering RA values in months where the storage ELCC was found to be less than 100%. CESA responded that the CPUC should affirm that standalone storage resources have a four-hour NQC methodology that should not be modified as part of this ELCC analysis.

See CESA’s comments on June 13, 2019 and reply comments on June 18, 2019 on the Proposed Decision

On July 5, 2019, D.19-06-026 was issued without modification for the QC of combined resources, except for third-party DR resources. The key change from the PD was that the final decision deleted most of the rationale for why it did not adopt a QC for combined gas-plus-storage, solar-plus-storage, and wind-plus-storage resources, instead explaining that combined QC value issues raise “many questions that we are unable to answer at this time.” It appeared like the CPUC recognized the comments from parties like CESA that raised objections to the rationale used to decline adopting a QC methodology for combined resources. However, as compared to the PD, the decision recognized that the 2017-2019 exemption from load impact protocols (LIPs) granted from D.16-04-045 for third-party DR resources was expiring and ultimately adopted PG&E’s and SCE’s proposal to use LIPs and/or (based on the PD in A.17-01-012, et al.) historical information from dispatches, tests, or “similar” resources to establish their QC on a year-ahead and month-ahead basis. This will likely present challenges for DRAM resources where LIPs or other historical methods cannot reasonably set the QC for resources that have yet to be procured and aggregated to be put in year-ahead and month-ahead supply plans

Hydro Qualifying Capacity (QC) Methods

Background

The CAISO explained that hydro resources may be shown up to their full QC value but uninformed by forward-looking water conditions, with non-dispatchable hydro resources receiving credit based on three years of historic availability and dispatchable hydro resources claiming full nameplate capacity as RA. However, some LSEs have expressed concern that there is pressure to show or offer their full RA capacity, which may exceed capabilities if below average hydro year and thus be subject to RAAIM penalties, even as a resource with conditional availability. The CAISO depends on accurate showings to inform reliability conditions and make potential backstop designations.

Overall, this is not CESA’s focus area, but this may be worthwhile to monitor to understand how QC methodologies for weather-sensitive resources (e.g., BTM DR and storage) could be impacted.

Working Group

On February 12, 2020, a working group meeting was held where PG&E raised this issue because, in their view, hydro resources do not have their availability reflected in the CAISO market based on the current QC methodology. The existing QC counting rules for hydroelectric resources likely overstates the availability because it does not reflect variability driven by hydrological conditions, weather patterns, FERC licensing, upstream powerhouses, and storage levels. PG&E also added that there are no clear criteria or CAISO and CPUC consensus on the definition of dispatchability for hydro resources.

As a result, PG&E proposed an exceedance methodology that measures the minimum amount of capacity made available to the market by a resource in a certain percentage of hours – i.e., availability assessment hours (AAH). The QC will be calculated based on a ranking of the generation in the previous 10 years of day-ahead market self-schedules and economic bids for each hydro resource.

By contrast, SCE proposed a derating calculation of the NQC of hydro resources that account for water availability, with RAAIM only applying for mechanical outages. This alternative approach calculates the derate factors based on weighted offered capacity availability during the 5am-9pm window over the past two years plus a third year in the past 10 years that identifies a “dry year” (i.e., lowest capacity) to prevent showing or offering unavailable or undependable capacity. SCE found this approach to better incentivize performance that still accounts for seasonality, uncertainty, and other environmental and regulatory factors outside the resource’s control.

Among the two, CAISO supported SCE’s approach since it aligned with their UCAP proposals in the RA Enhancements Initiative, and they agreed that resources would still be incentivized to offer as much capacity as possible into the market (i.e., not offering reduces future showing potential). The CAISO added that the capacity values could be updated to reflect more current conditions.

On June 30, 2020, D.20-06-031 was issued that adopted the hydro QC consensus proposal for 2021 RA year implementation to generate monthly QC values based on the previous 10 years of same-month bid-in availability (self-schedules or economic bids). For each month, the historical offered capacity in the AAH is used to calculate a 50% exceedance (or median) and a 10% exceedance value. The 50% value is weighted 80% and the 10% value is weighted 20% to determine the monthly QC value. Mechanical outages would be excluded from the calculation. This is an optional methodology and the CAISO would update its rules to give resources that choose this option an exemption from RAAIM penalties for outages from lack of water availability, but that exemption does not apply to those using existing methodologies.

Import RA Capacity

Background

RA imports include resource-specific imports and non-resource-specific imports, where the former includes resources that are pseudo tied and dynamically scheduled into the CAISO and are identifiable on CAISO supply plans.

In October 2004, D.04-10-035 established that the qualifying capacity (QC) for import contracts is the contract amount if the contract: (1) is an Import Energy Product with operating reserves; (2) cannot be curtailed for economic reasons; and either (a) is delivered on transmission that cannot be curtailed in operating hours for economic reasons or bumped by higher priority transmission or (b) specifies firm delivery point (i.e., is not seller’s choice).

In October 2005, D.05-10-042 established that non-unit specific, liquidated damage (LD) contracts would be phased out of use in the RA Program. These types of contracts increase the possibility of double counting resources and are not subject to deliverability screens. Both of these concerns had the potential to impact long-term grid reliability. However, the CPUC created one category of non-unit specific LD contracts that would not be phased out: LD contracts that met import deliverability requirements and demonstrated sufficient physical resources associated with them (i.e., spinning reserves and firm energy delivery). D.05-10-042 stated that firm import LD contracts do not raise issues of double counting and deliverability that led us to conclude that other LD contracts should be phased out for purposes of RA requirements. The CPUC noted that firm import contracts are backed by spinning reserves.

RA imports are only required to bid into the day-ahead market (DAM) and can bid at any price up to the $1,000/MWh offer cap without any further obligation to bid into the real-time market (RTM) if not scheduled in the DAM or residual unit commitment (RUC) process. Existing rules could therefore allow a significant portion of RA requirements to be met by imports that may have limited availability and value during critical system and market conditions. For instance, RA imports could be routinely bid significantly above projected prices in the DAM to help ensure they do not clear, thus relieving them of any further offer obligations in the real-time market.

On December 23, 2019, an Order was issued granting a stay on D.19-10-021 given the potential harm to parties of the decision, effective until the disposition of the various applications for rehearing.

Track 1 of R.19-11-009 will consider revisions to the RA import rules, with a report expected in early February 2020 and a proposed and final decision expected in April and May 2020, respectively, and will address the following issues:

• What types of import resources should be counted as RA (e.g., resource-specific imports with a must-offer obligation, non-resource specific imports for firm energy)?

• What rules should govern resource-specific RA imports, including what should be required by the CPUC to demonstrate compliance?

• What rules should govern non-resource specific RA imports, including what should be required by the CPUC to demonstrate compliance?

• Should the CPUC consider allowing firm, fixed priced energy contracts paired with an import allocation to count for import RA? If, so, how?

Resource-Specific RA Requirements (Track 3 in R.17-09-020 and Track 1 in R.19-11-009)

On July 3, 2019, a Ruling was issued that echoed the CAISO’s concerns from the RA Enhancements Initiative around “speculative supply” (i.e., no true physical resource or contractual obligation backing the RA showing) being relied upon by LSEs to meet RA requirements, even though unspecified imports may not provide firm energy delivery when the grid needs it the most. Based on a data request to the LSEs, the CPUC confirmed that import providers are only required to provide energy and operating reserves if its day-ahead market bids are selected and may be receiving capacity payments despite bidding themselves out of the day-ahead market with no intention to provide energy in the CAISO market. Thus, in this Ruling, the CPUC is aiming to clarify existing policy and seeking to determine whether action is needed to ensure the integrity of the RA Program.

Opening comments were submitted where almost every party disagreed with requiring actual delivery of energy from import RA as this is beyond the requirements of any other RA product where energy delivery is not required unless self-scheduled or scheduled/dispatched by the CAISO. For example, Morgan Stanley explained how a real-time bidding obligation would cause import RA resources to not offer their capacity into the CAISO market or add in the opportunity cost of losing out on other market revenue opportunities, thereby leading to lower liquidity and higher RA costs in general. The CAISO and Powerex emphasized the need for import RA to be backed by an identified physical resource. To address reliability risks, PG&E recommended some demonstration of delivery to a specific intertie, while SCE proposed two alternatives – one where the LSE acts as the scheduling coordinator to ensure the RA capacity is realized, or to have all import RA contracts specify an energy bid price that cannot be exceeded by the scheduling coordinator.

A key source of differences lied in whether “firm transmission” should be required to count for RA, with the IPPs and BPA supporting firm transmission capacity, power traders like Morgan Stanley opposing firm transmission because it limits the available pool of suppliers to firm transmission holders, and the IOUs and CAISO explaining that firm transmission is a complex issue because it is necessary to be equivalent to internal RA resources but may also prevent economic use of available transmission. SCE also added that an energy delivery requirement could make out-of-state resources reluctant to commit as RA resources and/or lead to imports acting as price takers with opportunity costs included in energy bids.  

Additionally, many parties cited analysis from the CAISO in the RA Enhancements Initiative to show that the issue is not urgent (CalCCA), is overblown (Morgan Stanley, SDG&E, Shell), or requires additional analysis before taking action (CLECA). The CAISO found that the risk of non-delivery of import RA may be smaller than originally thought. In worst-case scenarios, non-delivery of import RA amounted to only 10% of every month. With import RA only representing about 8% of peak summer hours in 2018, the CAISO determined that non-delivery of import RA amount to just 0.8% of the total, or equivalent to the average forced outage rate in the WECC. Furthermore, the CAISO is proposing a change in the Intertie Deviation Settlement Initiative that will increase incentives for import RA to deliver by eliminating the current 10% deadband that forgives deviations in import deliveries – i.e., an over- or under-delivery charge of 50% of real-time dispatch locational marginal price. Together, the CAISO analysis found less of a concern but the CAISO still expressed the importance of LSEs specifying the source balancing authority for all import RA in monthly showings and not allowing the resource to be recalled by the native balancing authority. DMM, however, disagreed with the CAISO’s analysis, which focused on non-delivery for RA imports that actually received a real-time award and whether they were dispatched accordingly. DMM instead found that only 53% to 63% of RA imports may actually be deliverable in the highest load hours.

On September 6, 2019, a PD was issued that clarified the requirements governing the use of energy imported into California to meet RA requirements. Specifically, the PD found it reasonable to ensure that RA import contracts are structured to require energy to flow during peak system periods – i.e., the availability assessment hours (AAH) from 4pm to 9pm – and therefore be categorized according to maximum cumulative capacity (MCC) categories. In addition, the CPUC affirmed D.04-10-035 and D.05-10-042 that transmission capacity be assured for RA import contracts – i.e., cannot be curtailed for economic reasons or by higher priority on transmission lines. The CPUC indicated that it will engage in a deeper analysis of the RA import rules in a future phase of the RA proceeding.

Other than the DMM, most parties expressed concern that the firm energy requirement will lead to market inefficiencies and increase costs for LSEs and customers. They recommended that a decision on the import requirements should be postponed until a future phase or other stakeholder process, and that import RA resources should be subject to an alternative requirement.

On October 17, 2019, D.19-10-021 was issued that approved the PD with some modifications, including the removal of the requirement that energy must flow during the AAH window. The decision indicated that the CPUC has the authority to establish these new requirements and was not persuaded by parties’ comments given that D.04-10-035 and D.05-10-042 clearly delineates the requirements for an import contract to count as an RA resource. The following additional modifications were made:

• The term “firm energy” has been replaced with the term “energy product” that “cannot be curtailed for economic reasons” to mirror the existing requirements.

• The affirmed requirements do not apply to resource-specific RA, which the CAISO has visibility into (i.e., these requirements only apply to non-resource-specific imports).

• A self-schedule into the CAISO market for non-resource-specific RA resources is sufficient to satisfy the requirements since there is no guarantee of the delivery of energy without a CAISO market dispatch award, despite meeting its must-offer obligations.

This decision was important and had impacts on the IRP proceeding and the potential procurement that could be authorized/directed by the CPUC, as assumptions for imports counting toward RA determines whether there are residual needs to meet the reliability needs stemming from once-through-cooling (OTC) facility retirements. By affirming stricter requirements for imports to count towards RA, it creates a greater likelihood that new or existing in-state resource procurement will be needed.

On November 18, 2019, CAISO submitted a PFM of D.19-10-021 on that discussed how the decision is legally and procedurally deficient for modifying rules without substantial evidence and with significant modifications made in the day prior to the CPUC vote, especially considering that the late-coming revisions would compound market inefficiencies (e.g., self-scheduling during solar overgeneration hours). Separately, Powerex also submitted a PFM on the same day to eliminate the self-scheduling requirement and to instead eliminate non-resource-specific supply from the RA program.

On February 4, 2020, the CAISO prepared a matrix summarizing existing CAISO tariff requirements for import resources to provide a common understanding of those requirements as parties discuss potential prospective rule changes related to how capacity outside the CAISO balancing authority area may provide RA capacity. This matrix highlighted how import resources without pseudo ties do not have real-time bidding requirements if not selected and scheduled in day-ahead market, unlike generating units with short or medium starts.

On February 14, 2020, a workshop was held. Since imports are increasingly being relied upon for RA and because reliability issues primarily arise in real time, CPUC staff argued that import resources must have real-time must-offer obligations like internal resources. Non-resource-specific energy requirements could be imposed, according to the CPUC staff, which would better ensure energy delivery but would reduce the CAISO’s ability to address ramping needs. There were several common areas of discussion at the workshop, including:

• Physical resource specificity: CAISO, CPUC, Calpine, MRP, and Powerex generally agreed that resource specificity and physical supply commitments are needed, which would also help the CAISO gain a better understanding of actual marginal costs of import bids and be able to later detect bid gaming. CAISO added that this requirement could be met by a portfolio of external resources. However, CPUC and SCE commented that this approach alone would not resolve the issue of artificially high bids on an ex ante basis. Given the renewable goals in other states, CAISO also warned against the decreasing dependability of imports unless contracted for RA purposes in California. PG&E found the lack of CPUC jurisdiction over external suppliers and balancing authorities to make this an impractical solution. Shell added that a contract for any physical resource, not any single one, should be sufficient. Finally, DMM warned of the recallability provisions of import capacity to other BAAs.

• Firm transmission: While imports do not have to be “backed” by a single unit, CAISO, Calpine, MRP, and Powerex affirmed the need for firm transmission delivery. CPUC staff generally agreed with pseudo ties for resource-specific resources to establish equivalency to internal resources. However, PG&E and Morgan Stanley pointed out that this could result in only a few market suppliers with firm transmission rights making import RA available.

• Bid cap: SCE and Shell focused on weeding out high bids with a price cap or strike price that would operate like a “call” option, where energy is required to be delivered up to a maximum price. Specifically, SCE and Shell proposed a maximum strike price at $250/MWh when the prevailing gas price is below $10/MMBtu, which would increase to $500/MWh and $1,000/MWh, respectively, if the prevailing gas price is at or above $10/MMBtu but below $20/MMBtu, or if the prevailing gas price is at or above $20/MMBtu. Many traders argued that this price cap is too low and would not reflect the actual opportunity costs in other BAAs. CPUC staff also raised the possibility of bid caps or fixed-price energy contracts, but they also suggested that similar ends could be achieved through a reduction of system requirements or resource caps (e.g., MCC buckets). However, MRP argued that the offer cap would not guarantee that supply will be secured in advance.

• Energy requirements: CPUC staff suggested that energy requirements could be imposed, which would better ensure energy delivery but would reduce the CAISO’s ability to address ramping needs. Resource-specific import capacity would be limited to pseudo-tied or dynamically-scheduled resources while non-resource-specific capacity would require energy delivery and scheduling. PG&E supported the Staff Proposal to have import RA deliver energy at bids between -$150/MWh to $0/MWh instead of self-scheduling during the AAH hours. DMM and PAO supported the staff proposal as an immediate, though interim, solution while other options are developed. While energy contracting requirements could address high-bidding concerns, CAISO explained that a self-scheduling requirement for energy contracts does not address reliance on residual short-term bilateral market supply. All other parties commented on the potential adverse consequences of the must-flow approach on the CAISO’s energy markets and on congestion management.

On February 28, 2020, CPUC staff prepared a workshop report. Other parties submitted proposals and comments regarding RA import issues. CalCCA and Morgan Stanley recommended an “all of the above” approach that recognizes the different types of import products without reducing the liquidity of this resource, though both opposed the must-flow requirement of the Staff Proposal. Specifically, depending on the product, MSCG favored an offer cap, such as the “attestation product” that identifies a specific resource but does not have a pseudo tie into the CAISO grid and does not consist of the “energy product” that can be known by day-ahead via an e-tag. BPA and SDG&E also warned that the majority of import supply would not qualify if required to have dynamic schedules or pseudo-tied capacity.

On March 16, 2020, the CPUC issued D.20-03-016, determining that good cause has been shown to grant limited rehearing of D.19-10-021 on the following set of issues:

• Self-scheduling requirement, and as to the distinction between resource-specific and resource-non-specific RA import contracts

• Distinction between resource-specific and resource-non-specific RA import contracts, and to provide a sufficient evidentiary basis for this distinction

• Clarification of certain specific terms used in D.19-10-021, including “resource specific” and “resource-non-specific,” as well as to clarify the timeframe within which RA importers are required to self-schedule in the CAISO market

In response, many parties reiterated their previously held positions in R.17-09-020 but also echoed in Track 1 of R.19-11-009. Notably, CalCCA recommended that the CPUC apply the import RA rules in place prior to issuing D.19-10-021 due to the disruptive impacts on LSE RA compliance efforts in the near term, particularly for 2019 and 2020 RA year compliance. To provide clarity, CalCCA recommended a longer runway with any new import RA requirements to be established in place for 2021 RA procurement and showing timelines. Given the disruption, ESPs generally agreed on the need to grandfather existing import RA contracts.

On May 18, 2020, a PD was issued resolving RA import issues that essentially adopted the CPUC Energy Division’s Staff Proposal as being the best positioned and most feasible on a short-term basis and as being minimally disruptive to market participants. At the same time, other parties’ proposals (e.g., lower $500/MWh price cap) were rejected because they did not address the main issue around speculative supply while the CAISO/Powerex proposal requires further development to provide greater visibility into import resources to assess speculative supply issues.

In comments, Calpine, PG&E, and Department of Market Monitoring (DMM) were supportive of the PD, with DMM seeking to revisit these rules to allow import resources to participate more flexibly as an RA resource. However, many parties found the resource-specific resource definition as limiting. Due to concerns that this PD would reduce the overall supply of potential RA across the West, CalCCA and Shell recommended that the PD be modified to allow “resource-specific” RA imports to include a supplier’s pool of resources validated by the CAISO, especially as the CAISO has recently adopted intertie deviation penalties to incentivize performance from import resources, including from a portfolio of resources not tied to a specific balancing authority or point of delivery. Bonneville Power Administration added that there is not a guarantee that any resource from the Pacific Northwest can be dynamically scheduled into the CAISO on a long-term basis since dynamic transfer capability is allocated on a daily basis. As supporting evidence, Shell cited that only 600 MW would be allowed to be dynamically scheduled out of the 4,800 MW capacity of the Pacific AC Intertie. CalCCA also produced an analysis of the RA shortfall created by the new import resource definitions.

Many parties, including SDG&E, also opposed the self-scheduling requirement, which impacts price formation and leads to inefficient dispatch of not only the import resource but also other resources. Shell also commented that the cost of uneconomic dispatch will be built into the contracted energy price going forward. With the energy offer price range limitations only addressing overgeneration periods, the alternative to the self-scheduling requirement would only mitigate these concerns in those periods. Furthermore, BPA added that bid limits at $0/MWh is arbitrary and could be set higher and still address speculative supply. Other parties also raised concerns about FERC jurisdiction over wholesale electricity rates, leading to the CPUC decision as risking litigation. Meanwhile, other key stakeholders such as CAISO and SCE did not take a position in favor or against the PD but instead voiced that these requirements should be interim and/or further clarified.

On July 6, 2020, D.20-06-028 was issued that adopted new RA import requirements that tightened their eligibility and must-offer obligations, specifically including the following:

• Definitions: Eligible “resource-specific” RA imports are defined as those including a CAISO resource ID or for “pseudo-tied” and “dynamically scheduled” resources into the CAISO’s day-ahead and real-time markets (see CAISO Tariff Appendix A at 142 on pseudo-tied resources). The decision reasoned that the resource definitions above would put imports on a level playing field as internal generating units, providing the same reliability benefits.

• Self-schedule requirement: “Non-resource specific” RA imports must either self-schedule or bid at a level between -$150/MWh and $0/MWh during at least the AAH to be eligible as RA resource. By setting energy offer prices in this range and minimally for the AAH period, the decision aimed to address limit concerns about inefficient dispatch, reduced import RA supply, and increased need for other dispatchable resources. The decision also explained that many imports already self-schedule into the market.

• Information submission requirements: Import contracts must include the terms of sale of energy to the specific LSE, denominated in $/MWh or $/kWh as well as import allocation rights. Note that this is contrary to how energy deliveries are specified to the CAISO, not any given LSE. In addition, the energy contracts must not contain economic curtailment provisions and must be submitted in unredacted form to the Energy Division.

• Maximum cumulative capacity (MCC) buckets: Non-resource-specific import RA resources would be subject to the MCC buckets based on the pattern of their self-scheduled energy.

Despite some parties’ recommendations to the contrary, the CPUC explained that it does not have sufficient record evidence to make any determinations regarding a firm transmission requirement. Legally, the CPUC also argued that the state has jurisdiction over ensuring reliability while ensuring that in-state and out-of-state resources are treated comparably, which disputes parties’ concerns about discriminatory treatment for regulating wholesale energy rates. Notably, the decision acknowledged that the resulting reduction in RA supply and increase in RA costs, but coming with improved reliability of the import RA portfolio. With this decision, the CPUC explained that it completes the limited rehearing of D.19-10-021, and the stay of D.19-10-021 is no longer in effect. In other words, these new requirements would apply beginning for the 2021 RA compliance year.

Relative to the PD, the decision was revised to clarify that LSEs are expected to bid in accordance with the governing contract outside of AAHs and to specify that the non-resource-specific energy contract must include not only the price ($/MWh) but also the quantity delivered (MW) per hour and the delivery period (hours and days), thus tying the energy requirement into a capacity calculation. The LSE must take responsibility as the resource’s scheduling coordinator and perform all scheduling coordinator functions for the resource, whether directly or through designation of a third-party scheduling coordinator acting as the LSE’s agent. In instances where the contract language may not include a self-schedule or bid requirement because the LSE buying the RA import is the scheduling coordinator for the resource (or has appointed another entity to act as the scheduling coordinator), it is reasonable that an attestation by the applicable scheduling coordinator for the resource may be used to confirm the self-schedule requirement. In essence, the revisions were intended to clarify the terms and conditions of non-resource-specific RA contracts with LSEs. However, the CPUC added commentary that some market participants may still skirt the intent of this decision by continuing to bid at the price cap during non-AAH hours, suggesting that the CPUC feels they did not go far enough by only setting energy delivery terms for the AAH period.

With the adoption of this decision, there could be broadening of these requirements, pending the consideration of better alternatives in Track 3 proposals in the RA proceeding (R.19-11-009). The energy requirements generally raise concerns as well on the suppressing impacts on energy prices. There are also ambiguities related to how this decision might impact existing import RA contracts. Furthermore, for out-of-state storage and renewable resources developed with pseudo-ties, these rules may not be a concern, but if developed and contracted as non-resource-specific resources, then these self-scheduling requirements or bid limits would apply. Finally, the application of MCC buckets for imports are unclear, with energy requirements for AAH, which would suggest that imports are limited to Category 1 if non-resource-specific and would thus eat up the share that other energy-limited resources could meet.

Path 26 Constraint (Track 1 in R.17-09-020)

On October 23, 2017, a workshop was held to discuss the proposed elimination of the Path 26 requirement. The CAISO indicated its support for this requirement as being beneficial, especially in light of the uncertainty of OTC retirements and renewable development that can drastically change the patterns of grid flow and capacity needs. This issue will be monitored but CESA will not be involved.

On July 5, 2019, D.19-06-026 was issued that adopted the proposal, effective immediately, to eliminate the Path 26 constraint, which effectively limits the amount of capacity an LSE can procure on one side of Path 26 between the TAC areas of Northern (PG&E) and Southern (SCE, SDG&E) California. The constraint was found to be too restrictive to allow LSEs to procure available resources flexibly and at the lowest cost to customers, even as physical violations of the constraint are unlikely so long as LSEs procure for the minimum resource requirement in each TAC are

Local Capacity Area (LCA) Definitions & Study Criteria

Background

While seemingly prudent at the time (D.19-02-022) when LCAs were disaggregated in recognition of the “physics” of the system, smaller areas have turned out to exacerbate market power concerns, which may be addressed by the CPE implementation.

The LCR study determines minimum local resource requirement to maintain reliability standards under 1-in-10 peak summer load scenarios – criteria that was changed from N-1-1 in late 2019 by the CAISO to align with NERC/WECC mandatory standards. A working group was established pursuant to D.20-06-031 because CAISO’s revisions unexpectedly resulted in substantial increases in the local requirements in the Bay Area, going from 4,550 MW in 2020 to 6,353 MW in 2021. Under the contingency of two transformer outages, PG&E indicated that they could have backup equipment in 24 hours, but CAISO indicated that 30 minutes are required. The study results would thus require all resources in the Greater Bay Area to be contracted for Local RA. The working is tasked with addressing the following issues as identified in D.20-06-031:

• Evaluation of the newly adopted CAISO reliability criteria in relation to NERC and WECC mandatory reliability standards

• Interpretation and implementation of CAISO’s reliability standards, mandatory NERC and WECC reliability standards, and the associated reliability benefits and costs

• Benefits and costs of the change from the old reliability criteria “Option 2/Category C” to CAISO’s newly adopted reliability criteria

• Potential modifications to the current LCR timeline or processes to allow more meaningful vetting of the LCR study results

• Inclusion of energy storage limits in the LCR report and its implications on future resource procurement

• How best to address harmonize the Commission’s and CAISO’s local resource accounting rules

PG&E Other LCA Definition (R.19-11-009)

On February 21, 2020 and March 23, 2020, in Track 2 proposals and comments in R.19-11-009, AReM, PG&E, CalCCA, and CPUC Energy Division recommended that the re-aggregation of the six LCAs comprising the “PG&E Other” LCA. Since it was premature to do without analysis, Shell recommended a blanket waiver for LSEs’ local RA deficiencies should be granted in 2020 and implement re-aggregation for the 2021 RA year. Energy Division stated further that more granular requirements may have exacerbated market power concerns. However, several CCAs stood apart from CalCCA (such as Marin, Sonoma, and Pioneer) and opposed re-aggregation because it would have harmful impacts on those who have “met the challenges” of the CPUC’s disaggregation decision by securing three-year forward Local RA contracts. Rather, the central procurement entity (CPE) decision could address these challenges.

On June 30, 2020, D.20-06-031 was issued that declined to reaggregate the PG&E Other local capacity area but set forth a pathway to meet their RA obligations if the LSE makes the required demonstration for waivers and demonstrates procurement of local RA capacity with the collective procurement in the six disaggregated PG&E Other LCAs are met. The interim approach in D.20-06-031 would avoid re-aggregation and would provide time for the CPE to be implemented.

Local Capacity Requirements (LCR) Study Criteria (R.19-11-009)

On June 30, 2020, D.20-06-031 was issued that adopted the CAISO’s 2021-2023 LCR study where needs increased by 517 MW between 2020 and 2021, in part driven by updated NERC study criteria. The CPUC also established a working group to look into LCR issues, including an expedited review of the local reliability study criteria and the consideration of energy storage limits in the LCR report and its implications on future resource procurement, and how best to address harmonize the CPUC’s and CAISO’s Local RA accounting rules. The 2021 FCR was also adopted without much discussion.

CESA recommended that the Local RA Working Group should support decarbonization pathways and strive to evaluate charging or energy limitations in a granular fashion to avoid capping preferred resource procurement. A better understanding of study criteria and assumptions will play an important role in informing how QC values could be reflected in energy storage procurement, in contrast to the use of effectiveness factors that are currently being contemplated in the CPE implementation process. The latter creates significant uncertainties since effectiveness factors do not easily translate to QC values and are determined based on the overall resource portfolio and by studying one contingency scenario, not all.

See CESA’s comments on June 11, 2020 on the Proposed Decision

Maximum Cumulative Capacity (MCC) Refinements

Background

On January 21, 2020, a Scoping Memo was issued that divided the proceeding into four tracks. Track 2 will consider the system and flexible capacity requirements for the following year and local capacity requirements for the next three years, but importantly, it will address several priority items, including modifications to maximum cumulative capacity (MCC) buckets to address increasing reliance on use-limited resources.

Track 2 (MCC Refinements): R.19-11-009

On February 21, 2020, the CPUC published a Staff Proposal to update the MCC buckets using more recent load duration curves and to address reliability concerns from the increased reliance on use-limited resources, such as DR and storage that do not generate electricity. The same Mirant top-down methodology as adopted in D.05-10-042 was used. In addition, the CPUC staff clarified the definition of “available” as being “able to operate” for an entire month, such that a resource that bids 24 hours per day cannot be ensured to be called upon nor can one that is only available for a partial month, suggesting that availability should be tied to some physical capability of the resource, not just bidding capability. The proposal particularly targets DR and imports. To address this issue, staff proposed four options for consideration:

• Option 1: Incorporate 2016-2018 load duration curves. This simply updates the MCC buckets with updated data.

• Option 2: Incorporate 2016-2018 load duration curves and account for intermittent generators. Solar and wind resources would remain as Category 4 resources but would be limited with at least 56.1% of resources in this category needing to be 24x7 available; otherwise, solar and wind resources could meet 100% of an LSE’s RA requirements.

• Option 3: Incorporate 2016-2018 load duration curves and cap the DR bucket. Instead of no limit, the DR bucket would become the most restrictive and set dispatch requirements at 30 hours per year, or at least 6 or 12 times per month in the summer months.

• Option 4: Incorporate 2016-2018 load duration curves, account for intermittent generators, and cap the DR bucket. This option is a combination of Options 2 and 3.

Staff recommended the option with the most changes and restrictions (i.e., Option 4b) that would ensure at least 56.1% of resources in Category 4 have 24x7 availability and would restrict the DR bucket (i.e., for supply-side DR) based on an assumed 12 times per month dispatch in the summer months.

CESA recommended that the CPUC defer modifications to the MCC buckets to Track 3 of the current RA proceeding, as any modifications on this construct might become redundant or unnecessary considering the CPUC’s intention to reevaluate the RA program as a whole, especially in regards to energy needs. Furthermore, CESA argued that the application of the CPUC’s proposal on this subject could hinder California’s efforts to transition towards a decarbonized energy sector, while the proposed caps by LSE could impact liquidity in RA procurement. Proposals to redefine availability should be deferred to Track 3 in order to consider broader reforms and fixes to the RA Program and to how the CAISO market can send economic signals to incentivize the desired dispatch, as opposed to .

See CESA’s proposal on February 21, 2020, comments on March 23, 2020, and reply comments on April 2, 2020 on the Track 2 Proposals

CESA also joined a coalition of DER parties, including CEDMC and CEERT, that challenged the staff’s assumption that DR resources are “dispatched rarely” due to the mismatch between AAH between 1-6pm for 2016-2019 DRAM resources and the greatest grid need periods as indicated by market prices (i.e., 4-9pm). The joint comments expressed how the MCC proposal will cap both DR and DER procurement (2,232 MW) at close to current levels (1,742 MW), with 1,251 MW from IOU DR programs, 373 MW of DRAM resources, and 118 MW of BTM LCR storage. If a cap is set, however, actual availability of DR resources should align with the assumptions used to calculate the DR procurement cap (i.e., 1,300 hours or 15% availability in the year based on 4-9pm availability for five days per week).  

On June 30, 2020, D.20-06-031 was issued that adopted a definition of availability based on the resource being physically able to dispatch during any and all hours associated with the minimum criteria of that bucket, holding aside use limitations or outages. In addition, the decision adopted the most stringent option proposed by Energy Division (Option 4b) since the current MCC buckets allow LSEs to meet up to 100% of their RA requirement with DR or storage resources:

The decision reaffirmed that IFOM wind and solar resources, as well as hybrid and co-located resources that are comprised of wind, solar and/or storage resources, are Category 4 resources. These are the only resources in Category 4 that do not have a 24-hour daily availability requirement. However, these resources do not qualify for the 56.1 percent of resources that must be available at all times. The decision also modified the DR cap included in Option 4b from 5.3% to 8.3% (or 3,735 MW of the current peak RA requirement), reflecting the 24-hour-per-month minimum availability requirement of DR and ensuring that the cap will not stifle supply-side DR growth. At this time, the DR cap will apply to all DR resources, including BTM storage-backed DR resources.

CESA urged the CPUC to defer the MCC buckets proposal until Track 3, but if adopted, it should be revised to remove consecutive hour requirements and clarify the categorization of various storage types. The environmental and solar parties agreed. In response, the decision discussed how updating the MCC buckets and limiting the DR bucket represent urgent reliability issues and was revised to clarify that use limitations that prevent it from bidding or dispatching would determine bucket categorization.

See CESA’s comments on June 11, 2020 on the Proposed Decision

There are several problematic areas, starting with the establishment of the MCC buckets based on physical availability. While solar, wind, and paired storage are still considered “Category 4” resources, they are still limited by the cap in place. Standalone four-hour storage, meanwhile, would qualify as a Category 1 resource. More significantly, despite CESA’s and SCE’s request for clarification in comments to the PD, the decision did not provide additional clarifications on whether a four-hour storage resource can count as a Category 2 resource if it can cycle twice in a day, or if it can discharge for eight consecutive hours at a derated capacity, leaving this to be ambiguous.

Multi-Year RA Requirements

Background

On October 4, 2017, the Order Instituting Rulemaking (OIR) was issued established the System, Local, and Flexible RA requirements for the 2019 and 2020 compliance periods. Issues identified by other parties included multi-year RA procurement.

Track 1

On February 22-23, 2018, a workshop was held on Track 1 proposals submitted by parties. A wide range of ideas was proposed and presented at the workshop, including multi-year RA requirements. AReM, IEP, and WPTF presented on the merits of multi-year RA requirements as enabling better price transparency, market liquidity, transactional ease, and regulatory/market certainty in the face of load migration and trend of unplanned retirements. Specifically, both AReM and IEP proposed variations of a declining three-year forward local RA obligation, which is set by the CAISO. focused on this idea because it would better prevent IOUs procuring resources on behalf of ESPs.

On April 24, 2018, a technical working group meeting was held to have a collaborative in-depth discussion with parties regarding RA program reforms that would maintain reliability while reducing potential costly backstop procurement – a key focus area for the CPUC staff. The working group covered both short-term and long-term solutions. Overall, there was some momentum toward a multi-year RA framework as most parties were willing to adopt such a framework, though the IOUs generally wished to limit it to at most two to three years to avoid getting stuck with the “wrong resources” that would also not reduce the need for backstop procurement. Generally, it appeared that the multi-year RA framework could be workable if forward obligations were differentiated by Local versus System RA and if the percentage and number of years of forward obligations balanced the need for cost recovery by generators with the forecast uncertainty and policy goals.

On June 25, 2018, D.18-06-030 was issued that approved the PD with only minor clarifications and modifications. Specifically, the decision clarified that LSEs under the multi-year Local RA framework could also procure Flex RA attributes when procuring for multi-year Local RA. Whereas the PD set a 100% local requirement for the first two years, the decision was slightly modified to reduce the second-year requirement at 95% to reduce the risk of over-procurement. The key takeaway from this decision was that the CPUC is concerned about how load migration has been impacting (and will continue to increasingly affect) resource planning for reliability, as CCA expansion continues to grow and needed generators face retirements (with the decision even highlighting two such resources in Ellwood and Ormond Beach). Thus, the CPUC indicated that they decided to make major foundational changes to the RA framework to improve market efficiency and enhance reliability, though they have concerns of the risks of turning to a centralized capacity market due to the state’s renewable goals. However, there is still much to be determined in terms of the success of this new framework, given that the details must be developed in Track 2. Overall, the decision provided guidance on developing a multi-year Local RA framework and central buyer concepts, while kicking most all other issues to Track 2 to allow for more record development.

The decision supported the implementation of a multi-year Local RA framework starting for the 2020 RA year. No specific proposal was adopted, but the decision provided guidance that stakeholders should develop details of the framework in Track 2. Specifically, the decision directed minimum 3- to 5-year duration requirements and a 100% and 95% requirement, respectively, to procure under multi-year Local RA contracts for Years 1 and 2. Importantly, the goal of this determination was intended to mitigate backstop procurement in the most critical areas.

Multiple parties supported the adoption of a multi-year framework for Local RA, though several parties (CAISO, IEPA, WPTF, DR Parties) recommended that the CPUC consider extending this framework to System and Flex RA requirements as well. Others (AReM, CLECA, ORA) supported the multi-year framework for Local RA but disagreed with adopting the 100% requirement for the first two years at this time, given insufficient record and risks of excess procurement when conditions change (e.g., forecast and load migration uncertainty) from first to second year. CAISO responded to these concerns and stated that full procurement of local resources in the second year is critical to the multi-year framework. SDG&E, while generally supportive, highlighted an important point in comments on how this framework may strand Flex RA, which is bundled with System and Local RA, as LSEs seek to procure Local RA only. The only party to outright oppose the multi-year framework was Shell, which cited insufficient evidence on the record.

As a short-term reliability measure for 2019, since the multi-year framework would not be implemented until 2020, the decision also directed the IOUs to bilaterally re-negotiate for resources expected to retire (e.g., Ormond Beach and Ellwood generating stations) rather than allowing these resources to fall into backstop procurement. Costs for this would be allocated similar to other cost allocation mechanism (CAM) resources. The IOUs expressed concern with becoming the default backstop entity and with being required to bilaterally negotiate with at-risk resources rather than considering alternatives. However, the IOUs, along with TURN and ORA, seemed to be fine with this requirement so long as the re-negotiated contract is more cost effective than the resource would be under backstop procurement and the costs of the contract are fairly allocated to all affected entities. The CCAs also conditionally supported this as an interim, not precedent setting, measure.

Track 2

On July 19, 2018, a workshop was held that focused on multi-year RA and central buyer proposals from the CPUC Energy Division, Calpine, IEP, IOUs, CCAs, ESPs, and CAISO, which will likely dominate the ‘mind-share’ in Track 2. Overall, there appeared to be some consensus forming around the Multi-Year Local RA Framework with the majority of parties supporting variable requirements (i.e., Local RA requirements updated regularly), allowance of load migration, and forward procurement between 3-5 years but with some variance on the target requirement for each forward year.

Among the parties, PG&E stands out as seeking 100% forward procurement for five years, which may stem from the high levels of load migration it has faced over the past few years, whereas the non-IOU LSEs commonly proposed forward target requirements that would drop to larger degrees given the long-term load uncertainty faced by ESPs and the self-provision of procurement desired by CCAs. Interestingly, CPUC Energy Division and IEP appear to be aligned in terms of supporting a five-year framework with steadily decreasing target requirements every year, with minor differences. Overall, in CESA’s view, the CPUC will need to make a determination that balances the interests of: mitigating risks for stranded procurement by overextending forward procurement years and targets; ensuring sufficient procurement flexibility to account for changing load and resource mixes; and providing greater procurement certainty for existing generators.

On November 21, 2018, a PD was issued that considered the duration of a multi-year forward RA program. The PD determined that a three-year duration has a consensus among parties, mitigates over-procurement risks as local requirements change as transmission projects come online and modeling assumptions change, and provides an opportunity for preferred resource alternatives to be developed to reduce local capacity needs in the near future. The PD explained that it was not convinced a five-year duration would be needed to provide financial stability and market signals, though longer-term contracts are encouraged in general. However, the PD adopted the CAISO’s proposal for 100% requirement for Years 1 and 2 and 80% requirement in Year 3, where the three-year duration addresses the much of the over-procurement risks from a high Year 3 procurement requirement amount in response to some parties who proposed a lower Year 3 requirement. The PD also expressed less concern for over-procurement to some degree given that excess Local RA resources could also qualify for System and Flex RA.

To establish the local capacity requirements under this multi-year forward RA program, the PD proposed to continue to use the CAISO’s existing one- and five-year Local Capacity Requirements Technical Study (LCRTS) studies but with engineer-managed adjustments for CAISO-approved transmission projects in any of the three forward years. The one-year study will form the basis for local requirements for Years 1 and 2 and the five-year study will inform the Year 3 requirements. The PD reasoned that this would use a study that already is in place and works while providing for year-to-year flexibility to ensure accuracy. The CAISO’s proposed essential reliability resources (ERR) study was rejected to be formally part of the framework but the PD adds that it could be used as guidance for central buyers.

Many parties (28) filed comments on the PD, but no party opposed the multi-year Local RA framework. IEP and NRG proposed the PD be modified to increase the Year 3 requirement but was otherwise supportive. Given the lack of opposition to the three-year Local RA framework, there may be a splitting of the PD to only approve this aspect but not the central buyer proposal.

On March 4, 2019, D.19-02-022 was issued that adopted requirements for implementation of a multi-year Local RA procurement to begin for the 2020 RA compliance year but importantly punted on adopting a central buyer structure. For multi-year RA issues, the decision adopted a three-year forward procurement requirement for Local RA beginning in the 2020 RA compliance year due to the consensus among parties and the reduced financial and over-procurement risks, as compared to a five-year forward procurement requirement. These forward procurement requirements will be based on the CAISO’s existing one- and five-year studies, with the incorporation of engineer-managed adjustments for CAISO-approved transmission projects, which the decision found to ease implementation of these new requirements without extensive modification. Importantly, the decision adopted a 100% requirement for Years 1 and 2 and a 50% requirement for Year 3 as the “appropriate balance” that minimizes the stranded costs issue from the lack of a central procurement structure, but this requirement only applies to Local RA and is not extended to System and Flexible RA at this time.

In sum, CESA found the decision’s reduction of the Year 3 forward procurement requirement (from 80% in the PD to 50% in the final decision) to be positive for potential new energy storage procurement. The adopted requirements therefore provide some stability in the near term for existing gas generators needed for local reliability but also opens up more opportunity for greater competition in Year 3. The decision cited and agreed with CESA’s and other parties’ comments on the PD on this matter, so this is a positive incremental win.

On March 18, 2019, Shell submitted a PFM of D.19-02-022 to delay implementation of multi-year local procurement until the 2021 RA year, based on the deferral of the central procurement decision to Fall 2019. Without a decision on the central procurement structure, Shell argued that multi-year local procurement will be fraught with uncertainty and risk of stranded costs. Shell also petitioned that the decision be modified to provide LSE resource information from their monthly supply plans in an aggregated format.

On May 24, 2019, AReM, representing ESPs, submitted a PFM to modify D.19-02-022 to not mandate disaggregation of the “PG&E Other” local area into six separate local capacity areas (LCAs) for the 2020 RA compliance year. AReM argued that it does not object to disaggregation over time to address Local RA issues but found that immediate disaggregation would interfere with existing contracts in the PG&E Other local area. AReM argued that the decision to disaggregate the “PG&E Other” area potentially harms LSEs that have existing RA contracts for the PG&E Other area, including those that do not specify the facilities that will provide the RA because the contracts allow the seller to specify the resources at a later date. These contracts do not include a right to require the seller to provide Local RA in particular LCAs. If the Local RA procured for “PG&E Other” does not match the LSE’s newly-assigned LCRs in the now-disaggregated local capacity areas, the buyer may have to procure additional Local RA to satisfy its new LCRs. CalCCA and Shell supported the PFM, adding that PG&E has not yet “reconfigured” these contracts in accordance with these new disaggregated LCAs.

On August 8, 2019, D.19-08-005 was issued that denied Shell’s PFM and found that D.19-02-022 already considered the issues raised. For example, lowering the Year 3 requirement to 50% had the effect of minimizing stranded cost issues. In addition, the decision determined that contract summaries, including information on counterparty, resource type, location, capacity, expected deliveries, delivery point, length of contract and online date, have already been determined to be public and not market sensitive.

On October 3, 2019, D.19-09-044 was issued that denied AReM’s PFM because the CPUC was already aware of the existing multi-year Local RA contracts and the potential effect of the decision on these existing contracts. The decision also noted that there is some amount of risk with forward contracting due to the CAISO’s LCRs changing from year to year. Instead, the decision encouraged good-faith negotiations among buyers and to count these contracts to System RA needs even if LSEs are unable sell any excess local capacity.

On September 11, 2019, PG&E filed a PFM on to modify D.19-02-022 to establish an alternative “PG&E Other” LCA compliance mechanism, where LSEs make demonstrations pursuant to the Local RA waiver process and can be deemed compliant if RA resources were procured anywhere within the “PG&E Other” LCA. PG&E justified this petition due to the challenges of LSEs achieving compliance under the disaggregated “PG&E Other” LCA, as directed by the Track 2 decision (D.19-02-002) – an issue that was also highlighted in the CPUC’s State of the RA Market report. Particularly, PG&E discussed its research findings on how much of the capacity in the disaggregated areas have been procured for purposes unrelated to Local RA requirements – e.g., owned and operated by non-CPUC-jurisdictional municipal utilities that have little incentive to sell capacity to LSEs. D.06-06-064 had previously aggregated certain LCAs for RA purposes in order to address market power concerns. In response, AReM, Shell, and Calpine agreed with PG&E’s proposal, but IEP, MCE, and CCSF opposed the PFM for the shortened review period and lack of evidence for the change, which would have anti-competitive impacts on the CCAs who procured for Local RA resources in accordance with the recently-adopted rules, though they acknowledge that the rule changes were abrupt and have made it difficult to procure in the disaggregated areas.

Track 2: R.19-11-009

On February 21, 2020, in Track 2 proposals, PG&E and SDG&E recommended a modification to the three-year-ahead Local RA requirement allocation process that uses multi-year load forecasts, not Year 1 forecasts, which is more efficient and addresses load migration. Shell opposed this requirement due to the inability to anticipate load migration from one year to the next.

Planning Reserve Margin (PRM) Refinements

Background

On January 21, 2020, a Scoping Memo was issued that divided the proceeding into four tracks. Track 2 will consider the system and flexible capacity requirements for the following year and local capacity requirements for the next three years, but importantly, it will address several priority items, including modifications to maximum cumulative capacity (MCC) buckets to address increasing reliance on use-limited resources.

Track 2 (PRM Refinements): R.19-11-009

On June 30, 2020, D.20-06-031 was issued that found merit in authorizing Energy Division to facilitate a working group to perform a new LOLE study that could be used to reconsider the current 15% planning reserve margin (PRM) used to set system requirements. CESA understands the desire for a review of the current PRM due to the changing resource mix. If pursued, a consideration of PRM not just for peak system capacity but also energy and flexibility needs could be explored. Energy Division will facilitate a working group to develop a set of assumptions for use in the study and then perform it. There will be a future opportunity to comment.

Additionally, the decision adopted a PRM adder for DR QC only apply to System RA, which is based on the load forecast plus a 15% PRM, contrary to local and flexible requirements that do not incorporate a PRM.

RA Forecasting & Process (R.17-09-020 and R.19-11-009)

Year-Ahead Requirements

On October 23, 2017, a workshop was held to discuss this topic that was proposed by PG&E to shift the local RA requirement from an annual requirement over all 12 months to local RA requirements established on a seasonal basis, as a means to provide greater flexibility in how LSEs procure RA resources.  The CAISO, however, raised concerns about the implementation challenges and how this would not change the fixed costs of generating facilities.

On December 9, 2017, Draft Resolution E-4907 was issued that required new and expanding CCAs to register with the CPUC on or before January 1 in order to serve load in the following year. This registration process aims to ensure participation in its year-ahead RA program prior to beginning service. Because participation in the year-ahead RA program is currently voluntary for new and expanding CCAs, the Resolution observed that this is resulting in mandatory short-term RA procurement by the IOU for CCAs in their launch or expansion year, leading to potential short-term cost shifts to bundled service customers that are not recovered in the PCIA mechanism. The Draft Resolution thus proposed to allocate system and local RA requirements to new and expanding CCAs during the year-ahead RA process, and required that they procure 100% of their local RA and enough RA to meet 90% of their year-ahead system RA requirement by October. CCAs that registered and submitted their implementation prior to December 8, 2017 are exempt from these proposed new requirements. Overall, the CCAs that would be affected by this Resolution include Desert Community Energy, King City, Riverside CCA, Silicon Valley Clean Energy (and their expansion to Milpitas), and Los Angeles Community Choice Energy (and their expansion to 21 additional cities).

On January 11, 2018, Resolution E-4907 was issued. A key change from the Draft Resolution is that delays to CCA implementation due to the adopted provisions above are limited to one year. If a new or expanding CCA cannot comply with the new timelines, the Resolution created a process where the CCA can still seek a waiver to serve customers within several months of approval of their implementation plans. Waiver requests must be received at least 75 days prior to the RA compliance month in which the CCA wishes to begin service, and these requests may be granted if the CCA agrees to a payment for their allocation of RA. The CPUC largely maintained the Draft Resolution due to their concerns of “unlawful cost shifting” while creating some flexibility for CCA formation.

On February 16, 2018, the CPUC staff submitted three different proposals. First, the CPUC submitted a proposal to improve the processes by which LSEs file historical load information and year-ahead load forecasts (March-April of every year) and by which the CPUC subsequently allocates initial RA requirements (July) and revised RA obligations (September). The LSEs are then required to submit their final year-ahead RA filing in October. However, given significant load migration to CCAs, the CPUC found that there was a gap in the process where CCAs are formed and implemented during the year-ahead filing and allocation process and costs of that procurement are left stranded with remaining bundled customers (D.11-12-018 excluded power purchase transactions of less than a year in calculating the PCIA charge). Therefore, the CPUC staff proposed that all LSEs must participate in all aspects of the year-ahead RA process if they plan to serve load at any point during the following calendar year and that an LSE may only expand its territory in the following calendar year if its year-ahead load forecast and revised load forecast reflect that expansion. This proposal is meant to work in tandem with Resolution E-4907.

On February 22-23, 2018, a workshop was held on Track 1 proposals submitted by parties. A wide range of ideas was proposed and presented at the workshop:

• CCA load migration: Due to the dynamic nature of load migration to CCAs and ESPs, PG&E proposed to adjust the process to allow for monthly load migration adjustments for System, Local, and Flexible RA to ensure fair allocation of RA costs and to relieve RA obligations for IOUs for load it no longer serves. SCE proposed having RA to be credited at the PCIA benchmark value when selling RA to CCAs to better reflect the market price of RA resources and prevent cost shifting, rather than having this RA value be administratively set at $58/kW-year. The ESPs, meanwhile, seek to be able to opt out of procurement done on their behalf.

• RA transfer between LSEs: The CCA and ESP parties advocated for clearer and flexible rules to enable transfer of RA between LSEs, including how the IOUs would make excess capacity available to others. Centralized markets or “bulletin boards” were raised as ideas that could facilitate this transfer.

• Year ahead RA showings for new CCAs: The recently formed and forming CCAs focused their presentation on Resolution E-4907, which adopted a new process whereby new CCAs are required to make a year-ahead RA showing before implementation. Because new CCAs cannot participate in the year-ahead or month-ahead RA process until their implementation plans are certified by the CPUC, these CCA parties proposed allowing new CCAs to bilaterally negotiate the purchase of RA from IOUs and leverage a weighted average price for meeting RA requirements in excess of the CAM allocation.

As can be seen above, there were a wide range of ideas proposed to be considered for Track 1 and 2 of this proceeding. The unplanned generation retirement issue and CCA migration are key issues that might dominate mind share early on, leading to CESA’s issues to mostly likely be considered later in Track 2. CESA reiterated support for proposals that improves and enhances the Flex RA product, unbundles System and Flex RA, and authorizes RA counting for hybrid storage resources.

On June 25, 2018, D.18-06-030 was issued that adopted the CPUC Energy Division’s proposal to require all LSEs planning to serve load, including for an expansion, to participate in the year-ahead RA process, which entails submitting load forecasts and annual year-ahead filings in the following calendar year. The decision concluded that this requirement would ensure more equitable allocation of RA requirements and backstop procurement costs for collective deficiencies and more accurate load procurement, thereby minimizing cost shifts, including intra-year load migration costs. This determination was widely supported by parties, though some CCAs may be disappointed to see the Resolution E-4909 process waiver was not extended beyond 2018. The CCAs and ESPs generally opposed central buyer concepts because they oppose “on-behalf-of” procurement by other entities and want to control their procurement strategy for environmental and local development purposes.

Forecast Revisions

On November 14, 2018, the CEC’s Demand Analysis Working Group (DAWG) held its recurring technical stakeholder meeting to discuss the results of the 2018 California Energy Demand Forecast Update, which, for the first time, included an hourly forecasting methodology that can be used as a system-level benchmark for year-ahead RA requirements during the 2020 RA program cycle.

On June 19, 2019, CEC staff reviewed their load forecasting process and how they evaluate the need for LSE-specific adjustments (e.g., comparing IOU departing load forecasts with CCA/ESP forecasts) and apply adjustments for incremental effects of demand-side programs. LSE forecasts are credited with a share of additional achievable energy efficiency (AAEE) and load-modifying demand response (LMDR) to the extent that it is not already accounted for in their forecasts.

On May 15, 2020, CLECA, ESPs, and direct-access customer groups submitted a joint motion that requested that the CPUC establish a working group to consider the effects of the novel COVID-19 pandemic on electricity demand. In addition, they recommended that the low economic case in the CEC’s 2019 IEPR forecast be used for the baseline of LSEs’ System RA requirements for the 2021 RA compliance year. CAISO, PG&E, and SCE agreed with the need for a working group but recommended a more rigorous process be taken to assess load impacts, noting that load shapes may have changed but may not be reduced.

Forecasting, Waivers, & Penalties

On July 5, 2019, D.19-06-026 was issued without modification. The CPUC was investigating why there has been a significant jump in Local RA waiver requests in recent years, which may be tied to withholding in the market by generators in tight months and locations but may also have other causes. As a result of this recent trend, the decision made several changes to the Local RA waiver price and process, as well as other general clarifications on penalties, to help LSEs handle their RA obligations in the face of potential market power issues:

• Local waiver trigger price and penalty: The decision updated the local waiver trigger price, which is intended to protect the LSEs from having to buy RA from suppliers exerting market power but has not changed in value ($40/kW-year) since 2006, to an annualized value of the 85th percentile of the monthly Local RA prices for SP-26 ($51/kW-year). Setting the trigger price at this level was found to allow the CPUC to consider the highest priced capacity offers and give discretion to grant waivers in circumstances where market power may have been exerted. The decision declined to adopt local waiver trigger prices for partial-year offers based on the equivalent annual price given the lack of uniformity of RA prices across months. To match the local trigger price, the local penalty price was also increased to $4.25/kW-month. Additionally, a formal and transparent waiver review process via Tier 2 advice letters was established.

• Flexible RA penalty calculation: Currently, penalties for System RA and Local RA deficiencies are not cumulative, and the current rules are ambiguous on how Flexible RA penalties are treated when an LSE is faced with other RA penalties. The CPUC thus provided clarification for instances where an LSE faces both Flexible RA and System RA deficiencies. If an LSE has equivalent Flexible RA and System RA deficiencies, the System RA penalty price of $6.66/kW-month shall apply. If an LSE’s Flexible RA deficiency exceeds its System deficiency, the System RA penalty price shall apply to the MW amount of the System RA deficiency, and the Flexible RA penalty price ($3.33/kW-month) shall apply to the MW amount of the Flexible RA deficiency in excess of the System RA deficiency.

All parties were generally supportive of the waivers and penalties in response to the PD issued on May 24, 2019. AReM, representing ESPs, recommended that going-forward updates to the trigger price in future RA years be clarified. The IOUs, meanwhile, focused on the need to extend the waiver process to System and Flexible RA to even the playing field and to resolve how partial-year RA waivers are handled.

Furthermore, the decision made several changes to address the growth in CCAs and ESPs that has led to disaggregation of load and more challenges to the year-ahead forecasting process to allocate RA obligations, leading the CPUC to align and standardize forecasting definitions and methods that were found to be different across LSEs. The decision adopted a common definition for load migration – defined as load effects that an LSE cannot reasonably predict or control (e.g., customer transferring service from one LSE to another) but excludes: changes to approved implementation plans, customer class load profiles, weather assumptions, or customer meter data; new service requests; losses due to disconnects or force majeure events; transfers of load out of the TAC area; or forecasting errors. Importantly, load migration, as defined, shall be the only allowable reason for differences between initial and final year-ahead forecasts. The decision also established a Binding Load Forecast (BLF) process and affirmed that the CEC and CPUC has the authority and process (e.g., plausibility adjustment) to adjust an LSE’s forecast if there is under-forecasting found, recommended a meet-and-confer process to align load migration estimates among LSEs, established a data transfer process for non-IOU LSEs to obtain customer data from IOUs, established a conflict resolution process for contested claims on load, and established new plausibility review triggers (5% deviation) that would allow the CEC and CPUC to request additional documentation from new LSEs.

All LSEs generally supported the refined load forecasting procedures. The CCAs and ESPs requested certain clarifications on the “load migration” definition as it applies to different LSE types as well as on what qualifies as additional information that would qualify for exceptions to allowable load forecast revisions, such as wildfires, data delays from IOUs, and new rates or DER programs. The IOUs, meanwhile, focused on how the PD overlooked PG&E’s proposal to establish a multi-year load forecasting process to align with new multi-year Local RA requirements

On February 21, 2020, a Track 2 proposal was submitted in R.19-11-009 by SCE to establish a limited waiver process for providers of last resort (POLRs) to be waived of System and Flexible RA requirements associated with unplanned load that was returned with insufficient time or was not transferred from the POLR to another LSE due to inaction by that LSE, which would reduce the cost burden on IOU bundled customers. However, in response, WPTF commented that “all commercially reasonable efforts” should be made, such as pursuing RA contracts that the CCA may have executed to cover the RA obligations of the load in question.

On June 30, 2020, D.20-06-031 was issued that adopted a shaped system penalty price that is $8.88/kW-month in summer months (May to October) and $4.44/kW-month in non-summer months – an increase to prevent “leaning” among LSEs and incentivize procurement. However, system and flexible waiver processes require further development and study, but it is allowed for providers of last resort (POLR) when IOUs must serve unplanned load. In comments to the PD, the CCAs and ESPs opposed the removal of the waivers and change in the penalty structure because, whereas buyers are subject to steep penalties for failing to procure enough RA despite their best efforts, sellers face no corresponding penalty for failing to sell their supply in a timely fashion, thus exercising market power. The suggested changes in the comments were not reflected in the final decision.

Resource Adequacy (R.14-10-010)

Background

On October 16, 2014, the Order Instituting Rulemaking was issued that marked the beginning of this proceeding.

On December 23, 2015, a Scoping Memo was issued that divided the RA proceeding into two separate tracks and identified four primary issues to be addressed: local and flexible RA requirements for 2018, a durable Flexible Capacity Requirement (FCR), multi-year RA requirements, and Effective Load Carrying Capacity (ELCC) of wind and solar resources. 

Track 1

The primary focus of the Track 1 Decision will be to adopt local capacity requirements (LCR) and flexible capacity requirements (FCR) for RA compliance year 2017, as well as to adopt refinements (not fundamental changes) to the RA program.

On July 8, 2015, ED Staff issued a document describing the inputs and assumptions for use in probabilistic reliability modeling and issued a paper providing the results of the modeling in the form of average ELCC of solar and wind generators in the CAISO in 2016. Average ELCC for solar resources in 2016 equaled approximately 63% and the average ELCC for wind capacity was 12.6%. The values were not specific to location or individual technologies within the solar or wind types. 

On June 23, 2016, D.16-06-045 was approved that adopted local and flexible capacity obligations for 2017 as well as certain changes to the RA program. The total local capacity requirement decreased by 3.1% from last year, while flexible capacity requirement showed substantial increases from this year. Allocation of Flexible RA Requirements has been deferred to Track 2.

In response to LCR changes stemming from the Aliso Canyon situation, D.16-06-045 (1) directs SDG&E and SCE to file Tier 2 Advice Letters establishing appropriate mechanisms to track changes in Local RA costs resulting from the shift in Local RA obligations from the LA Basin to the San Diego sub-area; and (2) asks the CAISO to provide analysis of potential responsive changes to the Local RA program in the 2018 LCR Study if Aliso Canyon operations continue to be constrained.

Track 2

The focus of the Track 2 Decision is to adopt a durable FCR program. The Scoping Memo anticipates that the level of FCRs may vary from year to year (as LCRs have) but it "intend[s] the definition of the flexible capacity product(s) and process for setting FCRs to remain constant beginning with RA compliance year 2018." Parties are encouraged to take a "long view" in drafting proposals. The scope of issues for Track 2 is:

1. What reliability need(s) must FCRs be designed to meet?

2. What definition of one or more flexible capacity products should be adopted to meet need(s)?

3. How should annual FCR requirements be set to meet need(s) with the defined product(s)?

4. What, if any, related changes to the RA program should be made to best meet the reliability needs?
   
   

The Scoping Memo highlights the question of identifying reliability needs that should be addressed by the FCRs (Question 1) as a precursor to consideration of Questions 2, 3, and 4. Unlike the previous Scoping Memo that identified a "Phase 3" of this proceeding to address DR issues, this revised Scoping Memo states that these issues can be addressed in the two tracks here or in the Demand Response (R.13-09-11) proceeding.

On April 5, 2016, a Track 2 Workshop was held where CESA presented on the following key points:

• The CPUC should ensure its durable flex product addresses critical system needs, including downward flex needs, and not assume spot markets will guarantee capacity

• Downward flex needs are not ‘just operational’ and setting the ‘right’ RA product requirements will influence the future portfolio of resources

• Cost considerations are overstated and should not override the basic purpose of RA to provide reliable capacity

• Durable product designs should not rely on ex post corrections

• Decoupling or unbundling of Flex RA (EFC) and System RA (NQC) should occur to allow easier transactions with smaller resources and broaden the pool of Flex RA resources

The CPUC posted a Track 2 Workshop Report on June 1 summarizing the discussion on flexible RA issues from the April 5 workshop.

See CESA's comments on June 29, 2016 on the Track 2 Workshop Report.

Track 3 (Phase 3)

On September 13, 2016, the CPUC issued a Phase 3 Scoping Memo, which will address unresolved Track 2 issues and additional issues for planned resolution in June 2017. The CPUC proposes to address four primary issues: local and flexible RA requirements for 2018, a durable form of FCR, multi-year RA requirements, and ELCC of wind and solar resources. The primary focus of Phase 3 will be to adopt LCRs and FCRs for RA compliance year 2018. The decision may also adopt refinements to the RA program, and this proceeding will consider proposals from Energy Division and parties for such refinements. 

Some of the key guiding questions include:

1. Have the current FCRs changed the quality/quantity of resources procured by the LSEs to meet RA requirements since 2015?

2. Have the FCRs changed the overall quality/quantity of resources bidding into the CAISO markets (vs. self-scheduling)?

3. What are the characteristics of flexibility that are needed now and over the next five years?

4. What, if any, characteristics of flexibility are not currently supplied appropriately through the FCR program, other procurement programs, or CAISO markets?

5. What, if any, contractual, economic, or structural barriers exist that hamper the ability of existing/planned resources capable of providing flexibility from doing so?

CESA continues to advocate for the development of a durable Flex RA and multi-year RA program, and the decoupling of flexible and standard RA 'counting.' Furthermore, CESA recommended that the CPUC include studies of 'solar-plus-storage' and/or 'wind-plus-storage' to understand how ELCCs can change and improve if renewable generation is coupled with a studied-amount of energy storage. 

See CESA's comments on September 23, 2016 on the Phase 3 Scoping Memo.

On October 27, 2016, a workshop on RA load forecasting occurred to understand the methodology used in adjusting the LSE-submitted load forecasts for RA compliance. LSEs are required to submit peak load forecasts to be used for year-ahead and month-ahead RA program compliance, which the CEC later adjusts in its overall demand forecast. Specific topics discussed in the workshop included these adjustment mechanisms - i.e., IOU service area forecasts, coincidence factor (CF) adjustments, plausibility adjustments to the year-ahead process, demand-side management (DSM) allocation adjustments. 

On November 8, 2016, a workshop was held that focused on methodologies and details for ELCC counting treatment for wind and solar resources. The CPUC has not implemented ELCC but is statutorily required to do so.The CPUC staff seems supportive of the idea, but needs time and resources to model and calculate the new ELCC for such ‘plus-storage’ resources. The CPUC presented several options to adapt the annual ELCC to a monthly value, including a relaxation of the two-start requirement for Flex RA.

Other parties also presented. Calpine presented at the workshop about how solar production is over-counted in the RA market, causing other generation resources to be displaced. SCE presented on how a durable Flex RA product does not require extensive modifications to the interim product, while PG&E argued that the CAISO can meet day-ahead forecasts through the Integrated Forward Market and Residual Unit Commitment processes instead of real time capacity. CAISO discussed how long-start units are not available when flexibility is most needed. CAISO also favored restricting the definition of Flex RA to include only faster-starting, shorter duration units.

CESA is advocating for modeling a solar-plus-storage and wind-plus-storage ELCC so that any resources facing lower RA ‘counts’ as part of an ELCC implementation could consider adding energy storage to their renewable resource to boost their planning capacity.

See CESA's comments on December 1, 2016 on the ELCC workshop.

On November 9, 2016, a workshop was held to discuss the CAISO's ramping needs and how the current Flex RA product could be revised to better meet those needs. According to the CAISO, ramping deficiencies in the summer are tied to the fact that current Flex RA Category 1 resources are less effective during summer months when primary and secondary three-hour ramps are more likely to come consecutively, causing two-start resources to be less meaningful. The CPUC appears very likely to continue with Flex RA products, but it may be changed to focus more on two-hour ramping (versus the current three-hour ramping). This is good for energy storage because it will then fully qualify. This is in part because long-start units are not available in the Real-Time Market, when deemed needed.

CESA continues to advocate for consideration of a resource fleet that can reasonably and economically respond to overgeneration and downward flexibility needs, such as energy storage. CESA is focused on continuing with a Flex-Up RA product and on developing a Flex-Down RA product. CESA also supports shorter-duration Flex RA products, and more generally, the decoupling of Standard and Flexible RA 'counting'.

See CESA's comments on December 1, 2016 on the Flex RA Capacity workshop.

On January 27, 2017, a Ruling was issued that sought proposals for multi-year RA requirements by February 24, 2017. 

On February 7 and 14, 2017, two workshops were held that broadly covered the Phase 3 proposals and discussed potential refinements. Calpine presented their modeling work in collaboration with E3 to demonstrate how BTM solar must be modeled as a supply-side resource to accurately determine its contribution to meeting RA needs - i.e., BTM will otherwise continue to "count" toward RA requirements through its impact on load forecasts. Calpine/E3's methodology thus calculates wind and solar ELCCs assuming no other renewables are on the system, whereas the current methodology overestimates solar reliability contribution by assuming other renewables are on the system. While portfolio and resource class ELCCs should still be calculated by month, Calpine proposed that allocation of capacity value should be done through marginal ELCCs for individual projects based on a "time-window approach" (i.e., all projects that come online in a given year are treated as part of the same vintage) and that "diversity" benefit should be calculated from the difference between the sum of individual resource classes. Calpine discussed how this is important to send the correct economic signal for future procurement while protecting the ELCC values of existing projects from degrading due to new procurement. SCE echoed many of Calpine's points but focused on the need to move to marginal ELCCs since, under an average ELCC approach, existing resources could see a significant drop in capacity value even if their production does not change and new resources could receive a higher RA value even if they do not add any capacity value to the system. The CPUC proposed to compromise to estimate the effect of BTM PV on solar ELCC since RA obligations and NQC calculations do not account for or value BTM PV. This estimation was proposed to be accomplished by adjusting the proposed monthly solar ELCC by the ratio of the difference between the proposed solar ELCC and estimated RPS non-BTM PV only ELCC; this ratio would then be multiplied in each month's final solar ELCC. 

CESA presented at the workshop on how the product can be tuned to address multiple CAISO-identified issues, including insufficient ramping speed, high minimum operating levels for RA resources, and limitations of long-start resources in addressing real-time flexibility needs. CESA focused its presentation on a new two-hour product, which addresses each of those issues.

On June 29, 2017, D.17-06-027 was issued adopting LCR and FCR obligations for 2018 and refining the RA program. D.17-06-027 details the utilities’ procurement requirements for 2018, where the Flex RA needs increase slightly – ranging between 10,156 MW (July 2018) to 14,611 MW (December 2018) for 2018 and 9,292 MW (August 2017) to 14,426 MW (November 2017) for 2017.  The increase is primarily due to the increasing penetration of solar resources, which in turn affects the net load ramp. The continuation of the Flex RA framework is positive for energy storage. The total of all local areas increased from 24,549 MW in 2017 to 25,207 MW in 2018.

However, D.17-06-027 failed to address many other issues raised in the RA proceeding. The PD notes that the CPUC’s ambition to implement a ‘durable’ Flex RA program will not be realized in 2017 in time for implementation in the 2018 RA compliance year, leaving the interim FCR in effect for 2018. Other unaddressed issues include:

• Multi-year RA procurement: The CPUC determined that this could not be done until a durable FCR is established.

• Fast dispatch of slow-response resources: The CPUC will work to implement SCE’s proposal to allow a portion of a slow-response resource that can reliably respond within 20 minutes to receive local RA credit.

• New Two-Hour Maximum Cumulative Capacity (MCC) Bucket: CESA and other parties proposed variations of this idea, but the CPUC defers on this idea given the ‘wide variety of opinions’ until further analysis.

CESA’s proposed ideas for a Flex Down RA product and an ‘ELCC count’ for solar-plus-storage were not addressed in D.17-06-027.  The CPUC seems to be unready to take major actions on RA, aside from implementing a state law requiring a new RA counting methodology for wind and solar, known as ELCC. In light of the vast areas of ‘no action’ by the PD, the CPUC proposes to muster working groups to tee up many topics for further review.

One major area of change is the CPUC’s proposal to implement an ELCC for wind and solar. This change will lower the RA value of solar from today's ‘exceedance’ approach, although there will be a measured transition to the full ELCC, which the CPUC determined to be ‘overly abrupt’ for solar resources. Wind's RA value is relatively unchanged. The CPUC is statutorily directed to count RA value of solar or wind using an ELCC approach, so this change is a compliance action by the CPUC.

In the table above, the CPUC adopted its ‘Solar Proposal 2’ levels for ELCCs for solar and wind for 2018, which are adopted in D.17-06-027 instead of the CPUC’s other proposal or Calpine’s proposal.  Values will change every year. CESA recommended an ELCC methodology for solar-plus-storage and wind-plus-storage resources and expressed disappointment that the PD failed to discuss ‘plus-storage’ ELCC and two-hour MCC bucket proposals.

See CESA's comments on June 14, 2017 on the Proposed Decision.

On September 28, 2017, Resolution E-4888 approved SCE’s two RA contracts with:

• AES Alamitos located in Long Beach, CA for 2,010 MW (Units 1-6) from June 1, 2018 through December 31, 2019 and 1,165 MW (Units 3-5) from January 1, 2020 through December 31, 2020

• AES Huntington Beach located in Huntington Beach, CA for 451 MW Units 1-2) from June 1, 2018 through December 31, 2019 and 225 MW (Unit 2), from January 1, 2020 through December 31, 2020

However, the CPUC denied SCE’s RA contract with AES Redondo Beach located in Redondo Beach, CA for 1,355 MW (Units 5 - 8) from June 1, 2018 through December 31, 2019 and 849 MW (Units 5, 6, and 8) from January 1, 2020 through December 31, 2020. There was previous (but no longer active) concerns expressed by SCE and AES that these contracts were negotiated and executed as a bundled package. The two contracts were approved by the CPUC for local reliability reasons, but there was discussion among the CPUC Commissioners on the need to more greatly rely on preferred resources to meet local reliability needs identified in the future. Furthermore, this resolution may be important since it is the CPUC's first determination on the applicability of environmental justice considerations to RA procurement.

Resource Adequacy (R.17-09-020)

Background

On October 4, 2017, the Order Instituting Rulemaking (OIR) was issued established the System, Local, and Flexible RA requirements for the 2019 and 2020 compliance periods. The CPUC specifically sought comment from parties on the OIR on whether re-examination of the proceeding should occur, and if so, what processes would be helpful in conducting that re-examination. Parties are requested to identify and prioritize no more than ten issues relating to refinements to RA program elements, which includes the unaddressed issue areas identified in D.17-06-027.

CESA provided recommendations on CESA’s top priorities to include in the scope of the new proceeding:

• Updates and enhancements to the durable Flex RA product

• Authorization of capacity counting for solar-plus-storage (e.g., solar-plus-storage ELCC or other “plus-storage” tools)

• Counting for the full flexibility of energy storage and allowing for the EFC to exceed the NQC

• Consideration of capacity planning to meet downward ramping needs

• Enhancements that promote efficiency by reducing out-of-market capacity procurements.

Issues identified by other parties include multi-year RA procurement, revisions to Flex RA products and eligibility, seasonal RA requirements, local RA issues for DR resources, alignment of CPUC and CAISO local RA needs, timing of the RA process and obligations, disadvantaged communities considerations for RA procurement, examination of Capacity Procurement Mechanism (CPM) and Reliability Must-Run (RMR) designations outside of the RA construct, and potential advantages of a capacity market over a bilateral RA market. These issues were also discussed within the context of the growth of CCAs and how that would impact RA requirement allocation and procurement. Notably, PG&E suggested that the NQC values of DR resources and allocation of responsibility for replacing RA value of non-performing resources need to be resolved if DRAM becomes a permanent program.

See CESA's comments on October 30, 2017 on the OIR.

On December 4, 2017, a very brief Prehearing Conference (PHC), presided by Administrative Law Judge (ALJ) Allen and CPUC Commissioner Randolph, was held. The scope of the proceeding looks unlikely to change, even though the IOUs tried to expand the scope of the proceeding to include departing load charges. Other comments made in the PHC include the need for CPUC-CAISO collaboration, concerns about the proposed timeline for submitting draft 2019 Local Capacity Requirements (LCR) and Flexible Capacity Requirements (FCR) reports by March 16, 2018, and suggestions by parties to create separate tracks for the RA policy issues and the required RA study and reporting processes. A Scoping Memo is expected to follow, which will affirm the schedule outlined in the OIR.

On January 20, 2018, a Scoping Memo was issued that highlighted the need to consider the following trends in considering modifications to the RA framework:

• Recent out-of-market procurement of resources for local reliability

• Growth in CCAs

• Gas fleet transition considerations driven by IRP analysis and impacts on disadvantaged communities

• More variable weather and more weather-correlated generation

As a result, the Scoping Memo stated that it will prioritize solutions to reduce future out-of-market RA procurement in Track 1 of this proceeding. Track 1 thus focused on the following issues:

• Adoption of the 2019 LCR, FCR, and System RA requirements.

• Whether participation in the year-ahead RA showing should be required in order for an LSE to serve load in the following year.

• Reforms to RA program to reduce costly backstop procurement.

• Updates to ELCC modeling methodology.

• Alignment of RA measurement hours with CAISO availability assessment hours.

• Incorporate Flex RA rule revisions from FRACMOO Phase 2 Initiative.

In Track 2, the proceeding covered the following:

• Adoption of multi-year local RA requirements.

• Adjustments to local area rules (e.g., waivers, transparency on resources essential for local reliability).

• Track 1 overflow issues.

See CESA's comments on January 30, 2018 on the Scoping Memo.

On January 29, 2019, an Amended Scoping Memo was issued on that set the scope and schedule for Track 3 issues:

• Adoption of the 2020 Local Capacity Requirements (LCR) and Flexible Capacity Requirements (FCR), with draft studies by April 4, final studies by May 1, and final decision by end of June

• Adoption of the 2020 System RA requirements

• Revisions to the load forecast methodology

• Consideration of how storage and combined resources should be counted for RA credit

• Refinements to the third-party DR qualifying capacity methodology

• Consideration of other RA Proposals submitted by parties

On August 2, 2018, a prehearing conference was held where parties discussed whether evidentiary hearings are necessary, taking into consideration Track 2 testimony and workshops. On prioritization, SCE highlighted the need to address multi-year and central procurement and RA counting for resources and PG&E noted that its priorities are number of years forward for multi-year procurement, balance between ‘front-stop’ and backstop procurement, who the central entity is, and how to manage the transition period.

Status Update

On September 3, 2019, a Ruling was issued that attached the CPUC’s State of the Resource Adequacy Market report that was prepared pursuant to D.19-02-022 to understand the types of resources procured for RA, deficiencies by LSE, and resources with an NQC that were not shown in RA filings due to planned or forced outages. This document covers RA filings from the 2019 year-ahead filing through the September month-ahead filing. Notably, the report highlights that the majority of battery storage to date counts toward RA requirements as CAM/RMR/LCR resources, where RA credit is allocated to customers proportionally of multiple LSEs. On aggregate, LSEs met RA requirements in most months, though there was an approximately 500 MW cumulative deficiency in September resulting from the five LSE month-ahead system deficiencies, and adequate capacity was procured for each local area, except San Diego-Imperial Valley (San Diego-IV), which had deficiencies during the peak months of July through September. Some of the reasons cited for these local deficiencies was the lack of offers at reasonable prices, though the CAISO did not perform backstop procurement to address these deficiencies. Overall, this analysis indicated that the RA market is tight, in part due to the limited new preferred resource procurement (just 463 MW from January 2018 to July 2019) while also identifying how there was 850 MW that was physically available as well as 2,685 MW of unused MIC in September.

RA Local Waiver Requests

On October 30, 2019, CalCCA submitted a PFM of D.19-06-026 to request System and Flexible RA waiver requests for the 2020 RA year due to a tight RA market and despite the best efforts to solicit RA resources available or at reasonable costs. CalCCA suggested that this tightness in the market may be due to withholding from IOUs of their excess RA, leaving little for CCAs to pursue. While many parties supported the PFM as exceeding the scope of an affirmation and thus should grant the PFM, PG&E and SCE supported D.19-10-021 as a reasonable interim approach to address the potential reliability problems related to imports.

On October 31, 2019, multiple LSEs (17), including PG&E and SDG&E, filed Local RA waiver requests in advice letters due to either or some combination of the lack of available resources for contracting, unreasonable costs for certain System/Flex RA supplies (exceeding $51/kW-year thresholds), withholding of excess RA resources from other LSEs (e.g., PG&E), and regulatory uncertainty of the import RA decision. The disaggregation of “PG&E Other” local capacity area also appeared to play a major factor for certain LSEs in meeting local sub-area needs, where no offers were made to LSEs. Similar month-ahead waiver requests for January, February, and March 2020 were submitted by many of the same LSEs.

Resource Adequacy (R.19-11-009)

Background

On November 13, 2019, the CPUC issued an OIR to kick off this recurring but new proceeding (R.19-11-009) to address cyclical items, such as local and flexible procurement obligations, but also to address a number of outstanding or emerging issues identified in the previous RA proceeding (R.17-09-020):

• Examination of the broader RA structure to address energy attributes or hourly capacity requirements, given the increasing penetration of use-limited resources, greater reliance on preferred resources, rolling off of a significant amount of long-term tolling contracts held by utilities, and material increases in energy and capacity prices experienced in California over the past year.

• Potential modifications to the maximum cumulative capacity (MCC) buckets to address increasing reliance on use-limited resources to meet reliability and needs, and consideration of whether the CPUC should cap quantities of imports and/or use-limited resources (such as DR) consistent with monthly and/or annual load duration curves.

• Consideration of whether there is a benefit in expanding multi-year forward local RA requirements to system and/or flexible resources and how to address market power with multi-year requirements.

There were a number of other issues from R.17-09-020 that the OIR requested that the parties prioritize, which may include, among other things, RA counting conventions and market power mitigation measures. CESA provided our recommendations on the consideration of issues to be included in this new proceeding:

• The CPUC should develop a methodology that properly values hybrid storage resources, while refraining from employing the same ELCC methodology for storage as within the IRP proceeding.

• The CPUC should evaluate capacity needs to inform energy storage QC methodologies in order to properly signal to the market the resources needed for future procurement.

• The CPUC should further study system-wide and local capacity needs instead of establishing a cap for use- or energy-limited resources.

• The CPUC should evaluate the unbundling of System and Flexible capacity products in order to optimize the procurement of resources and support ratepayer benefits.

• Proposals to expand multi-year requirements for System and Flexible capacity should support preferred resources where economically viable.

On December 16, 2019, a prehearing conference was held where the ALJ asked parties to identify the top two issues to address, with a large majority focusing on the need to reassess the import-related decision. Informal working groups were formed to develop capacity counting methodologies.

See CESA’s comments on December 3, 2019 and reply comments on December 10, 2019 on the Order Instituting Rulemaking

On January 21, 2020, a Scoping Memo was issued that divided the proceeding into four tracks. Track 1 will consider revisions to the RA import rules, with a report expected in early February 2020 and a proposed and final decision expected in April and May 2020, respectively, and will address the following issues:

• What types of import resources should be counted as RA (e.g., resource-specific imports with a must-offer obligation, non-resource specific imports for firm energy)?

• What rules should govern resource-specific RA imports, including what should be required by the CPUC to demonstrate compliance?

• What rules should govern non-resource specific RA imports, including what should be required by the CPUC to demonstrate compliance?

• Should the CPUC consider allowing firm, fixed priced energy contracts paired with an import allocation to count for import RA? If, so, how?

Track 2 will consider the system and flexible capacity requirements for the following year and local capacity requirements for the next three years, but importantly, it will address several priority items, mostly related to capacity counting conventions, and conclude by June 2020:

• Modifications to maximum cumulative capacity (MCC) buckets to address increasing reliance on use-limited resources: Should the CPUC impose a cap on quantities of imports and/or use-limited resources (such as DR) consistent with monthly and/or annual load duration curves? How should be the MCC buckets be redefined (e.g., number of hours, time of day)? How should availability of resources be determined for placement of resources in buckets (e.g., operational limits of the resource)?

• Qualifying capacity counting conventions and requirements for hydro resources: What changes to counting conventions are needed? SCE and CAISO have volunteered to co-chair this working group.

• Qualifying capacity counting conventions and requirements for hybrid resources: Should the CPUC adopt a permanent methodology for counting of hybrid resources? CESA will co-chair the working group along with SDG&E.

• Qualifying capacity counting conventions and requirements for DR resources: What rules should be required for third-party DR (e.g., operation, testing)? How should load-modifying DR be counted? Are modifications to the load impact protocols (LIPs) needed (e.g., to ensure DR resources provide local and system reliability benefits)? PG&E, CPower, and PAO volunteered to co-chair the working group.

• Qualifying capacity counting conventions and requirements for solar and wind resources: Should marginal rather than average effective load carrying capability (ELCC) values be used for wind and solar resources? If so, how should this transition be implemented, given that current practice is to adjust all wind and solar resources’ ELCCs with each new ELCC study? SCE and Calpine volunteered to co-chair this working group.

• Re-aggregation of the “PG&E Other” area since D.19-02-022 disaggregated this local area but has been raised as an issue (e.g., local waiver requests).

• Changes to existing penalty structure and waiver process to address potential market power and other issues.

A proposed and final decision is expected in May 2020 and June 2020, respectively, for Track 1 and Track 2 issues. To move toward resolution on counting convention issues, the CPUC directed that parties form working groups that involve one IOU and one non-IOU to chair the development of areas of consensus and non-consensus on the hybrid capacity issues.

Track 3 will address more complex and somewhat less time-sensitive structural changes and refinements to the RA Program, including examination of the broader RA capacity structure to address energy attributes and hourly capacity requirements given the increasing penetration of use-limited resources, among other factors. Track 3 proposals are due by July 10. This track is expected to conclude in Q1 2021.

Track 4 was also roughly scoped to consider the 2022 program year requirements and other proposals that may be considered, which is expected to conclude by June 2021.