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Storage Equipment List

Background

According to Go Solar California, all solar energy systems receiving ratepayer-based incentives in California must utilize CEC-listed equipment. With the enactment of SB 1 (Murray) in 2006, the CEC was directed to establish eligibility criteria, conditions for incentives, and rating standards for projects applying for ratepayer-funded incentives for solar energy systems. The Eligible Equipment Lists cover PV modules, inverters (including smart inverters beginning in September 2017), meters, and related equipment. The CEC is now considering whether to develop a Storage Equipment List, similar to the lists already established for qualifying solar and smart inverters.

List Development

On August 16, 2018, CESA presented at a workshop to discuss the merits of a Storage Equipment List, as well as to consider whether non-smart-inverters should be “de-listed” from the CEC list. CESA conveyed that listing energy storage equipment on these lists will ensure consumer protection, mitigate safety concerns, support consideration for different energy storage technologies in key programs and solicitations, and provide standard performance information. CESA supported the CEC’s role in listing energy storage equipment that meet minimum criteria around safety and reliability (which is done through verifying equipment have the appropriate certifications) and in supporting the development of standard testing conditions to represent consistent and accurate performance. Until these standard test conditions are established, however, CESA did not recommend the listing of OEM-provided performance data in the Storage Equipment List.

See CESA’s comments submitted on August 31, 2018 in post-workshop comments

On February 26, 2019, a kickoff meeting for an energy storage technical advisory working group was held to discuss the merits of a Storage Equipment List. The working group will cooperate to identify the safety standards and appropriate testing protocols, including performance data on the list. The CEC changed the SB 1 guidelines to include battery energy storage systems (i.e., UL 9540 and UL 1973), but the CEC said it would be open to expand this list. The CEC explained that UL 9540 would be sufficient since it requires that certified energy storage systems be compliant with grid-support functions (i.e., UL 1741 and IEEE 1547.1). When asked about UL 9540A for thermal runaway, the CEC said it did not include it because it produces a variety of tested data that may not have much value now. The California Building Standards Office (BSO) requested that the CEC include the JA12 standard adopted in 2019 that allows battery storage as a compliance option, which would otherwise require a separate list to be maintained.  Furthermore, stakeholders raised the issue of field certification and how energy storage systems are installed, which may have site-specific factors to consider. PG&E and NEXTracker proposed that the list also consider microgrid islanding mode (e.g., synchronization and anti-islanding modes) and proper control settings as part of the scope of this list. Finally, the CEC said that performance standards for this list is not a priority at this time, as the focus is currently on minimum safety and reliability standards. Once testing standards are developed to cover the range of technologies, the CEC said it would take up this issue. CESA expressed that safety and performance can be interrelated, so a pathway to explore this intersection should be included in the scope.

On March 22, 2019, a working group meeting was held to share the initial draft of the list and explain different sections. The IOUs expressed their preference to separate the list for energy storage equipment since there are separate electrical and fire codes for energy storage systems (e.g., IFC Chapter 12, NFPA 1 Chapter 2), as well as their preference to include “hybrid” inverters on the battery inverter list. Inverter manufacturers added that there are additional NRTL efficiency tests for solar inverters that may not be applicable to hybrid storage inverters. Further review was discussed as being needed on UL 9450 Section 24 that deals with utility-grid interaction. Importantly, stakeholders were still confused to the purpose and use case of this list since the NRTL will already have a list of data. Given this, UL recommended that a link to NRTL databases be established to produce data for the equipment list. To address any confusion, the IOUs and UL clarified that energy storage systems (not used just for backup) will need to comply with UL 1741-SA and IEEE 1547 for grid compatibility since standards like UL 9540 is just a testing standard and references UL 1741-SA for certification.

On June 28, 2019, a working group meeting was held where UL provided a status update on their efforts to develop performance-testing procedures for energy storage systems and batteries. The NEMA ESS 1 (2019) and IEC 62933-1-1 (2017) standards as well as the PNNL and NREL 2016 protocols were reviewed to determine a standard reporting methodology for RTE for the purposes of the JA12 requirements.

Phase 1 Implementation

Beginning August 21, 2019, manufacturers can submit Battery and Energy Storage Systems (ESS) listing requests by accessing forms and instructions available on the new ESS web page, where the CEC provides general information, listing request forms, and instructions. Unlike batteries, note that ESS is defined as a “system” that includes batteries, inverter, energy management system (EMS), electrical circuits, and other electrical components, all together in one system.

To be listed, the manufacturer must do the following:

• Obtain NRTL certification to UL 1973 for Batteries or to UL 9540 for ESS systems, including the test report in both cases

• Manufacturer’s spec sheet(s) for all the requested model number(s), including the maximum continuous discharge rate

• Optional certification or testing by NRTL to UL 1741 including Supplemental SA, including to verify Volt/Var test with reactive power priority enabled and other test report summaries for Phase 3 smart inverter functions (for interconnection use cases)

• Optional certification by NRTL or SunSpec Alliance to the Common Smart Inverter Profile (CSIP) conformance testing procedures, including whether inverter is “Grid Support Utility Interactive” (for interconnection use cases)

Electrochemical batteries, intended to be uses in stationary applications, and have safety certificate to UL 1973 from a NRTL can be considered for listing. The CEC also established optional listing documentation requirements (declaration form) for Joint Appendix 12 (JA12) of the 2019 Building Energy Efficiency Standards, which outlines how a battery energy storage system, in combination with an on-site PV system, to qualify for compliance credit towards meeting the required energy budget. Requests are processed on a first-in, first-out basis, and involve an administrative screening (Phase 1) and technical evaluation (Phase 2). Only those requests Phase 1 will be reviewed for Phase 2. Listing requests can take between 30 and 45 days. The CEC updates the solar equipment lists twice a month, typically on the 1st and the 15th business day of the month.

Similar to solar and smart inverters, this development marks an important addition to support storage deployment, including in facilitating streamlined, safe, reliable, and compliant interconnection and program eligibility. In the next phase of the proceeding, the CEC will consider performance testing standards to be added to the storage listing information.

2018-2022 DR Application

Background

On January 17, 2017, each of the IOUs filed their applications. PG&E (A.17-01-012) proposed modifications to its existing programs - Capacity Bidding Program (CBP), Base Interruptible Program (BIP), SmartAC Program, and Automated DR (ADR) Program - and continuation of its two pilots - Supply Side II DR Pilot (to determine the customers' willingness to be dispatched frequently for RA and local distribution needs) and Excess Supply DR Pilot (to address mitigation of excess supply situations). SCE (A.17-01-018) proposed changes to BIP to provide higher incentives for resources that are able to meet 20-minute response requirements, discontinuation of the BIP aggregation option, reprogramming of BIP meters to record 5-minute interval data, and reduction of annual capacity payments for the Peak Time Rebate (PTR) Program. SCE also submits its Charge Ready DR Pilot for approval to examine charging behavior in workplaces, destination centers, and multi-unit dwellings. SDG&E (A.17-01-019) explained its intention to focus primarily on BIP and its Technology Incentive Program and proposed two pilot programs - Armed Forces Pilot (to test armed forces' ability to participate in an ADR program) and Overgeneration Pilot (to test the role of distributed storage at times of excess renewable supply). 

On March 1, 2017, a prehearing conference (PHC) was held to determine the parties, scope, and and schedule of this proceeding to develop future DR portfolios. CESA raised the same issues as in the above-referenced comments to ensure that net-export constraint issues are scoped into the proceeding for the 2018-2022 DR Applications. In a reply to protests, PG&E asserted that the net export constraint issue is outside the scope of this Application.

See CESA's  response on February 28, 2017 on the IOUs' 2018-2022 DR Applications.

On March 15, 2017, a Ruling and Scoping Memo was issued for the IOUs’ 2018-2022 DR programs to review the applications for compliance, reasonableness, and cost-effectiveness.

On April 5, 2017, a workshop was held where the IOUs each provided an overview of their 2018-2022 DR applications. One key issue to address in these applications is to ensure consistent baselines for supply-side DR resources and IOU DR programs. The CPUC staff also presented their proposal to integrate energy efficiency and DR programs to have common goals, funding sources, outreach, and policies. The IOUs generally supported this idea, while the DR parties generally did not. Other topics discussed at the workshop include focusing DR in particular geographic areas, cost-effectiveness, and coordination with other proceedings.

On June 26, 2017, PG&E and various stakeholders filed a Motion for approval of a settlement agreement.

On December 21, 2017, D.17-12-003 was issued approving the IOUs DR programs, pilots, and other activities for 2018-2022, with authorized budgets of $333 million for PG&E, $751 million for SCE, and $78 million for SDG&E. The decision directed closer oversight and monitoring of SDG&E’s DR programs and portfolios given the “less than satisfactory” cost-effectiveness ratios. Some funds were authorized and allocated for pilot DR programs intended to target transmission-constrained local capacity areas and disadvantaged communities. The decision also rejected the recommendations of the Joint DR parties to require uniform parameters for DR programs due to differences in marginal costs and load shapes across the IOUs that drive cost-effectiveness analyses, but directed the IOUs to identify parameters that could be made consistent and uniform statewide. Finally, the decision approved a settlement of A.17-01-012 between PG&E and various stakeholders, with the key provisions related to the Base Interruptible Program (BIP) and Capacity Bidding Program (CBP) summarized below. The only modification to the settlement agreement is that PG&E’s proposed Permanent Load Shifting (PLS) Program is not authorized. The settlement also framed issues that need to be addressed with further collaboration, including the CBP penalty structure, CBP operating hours, and CBP cost-effectiveness calculations, alternative baseline methodologies, and list of eligible residential Auto Demand Response (ADR) enabled end-use devices.

CESA’s interest in this application is specifically to address the “dual DR participation issue”. As noted in the decision, the CPUC has previously established three rules relevant to this issue: (1) duplicative payments for a single (overlapping or simultaneous) instance of load reduction or load drop is prohibited with payment only under the capacity program; (2) dual participation is permitted in two DR activities if one provides an energy payment and the other provides capacity payments; and (3) dual participation in two day-ahead or two day-of programs is prohibited. Electric Rule 24/32 also prohibits customers from simultaneously participating in a program provided by a third-party and bid into the CAISO market and an event-based utility-administered DR program. Despite calls from the Joint DR Parties for these dual participation rules to be reexamined, PG&E explained that these rules are in place to avoid conflicting signals due to multiple dispatches for the same intervals for the same capacity, ensure accurate baseline calculations, and avoid double payments. However, the decision declines to make a determination at this time and instead directed a workshop to make a final determination on this issue in a future decision in this proceeding.

On February 20, 2018, SDG&E filed an advice letter that implemented their new day-of two-hour notification product in their Schedule CBP.

On March 27, 2018, PG&E filed a supplemental advice letter that resolved the protests from the Joint DR Parties, who opposed PG&E’s modifications to increase the frequency of test events from two events in a calendar year to having an option to call one test even in each month of the DR season. Specifically, PG&E responded to the concerns expressed in the protest by creating an option for PG&E to call up to one CBP test event per month only during months where DR resources did not receive a market award in that month. The test event is not to exceed two hours in duration, will be based on the current approved price trigger, and will occur between the 20th day and the last day of the test event month.

On April 30, 2018, a webinar was held to review the IOUs' proposed evaluation, measurement, and verification (EM&V) plans. SCE proposed to conduct process-related evaluations approximately every two years, while "mature" DR programs that deliver consistent load impact results can be evaluated less frequently. 

On May 17, 2018, a workshop was held to discuss how the IOUs can make the parameters of their DR programs to be uniform while ensuring a positive cost-effectiveness analysis. This first meeting discussed the process and scope of this effort and discussed areas of potential alignment across the three IOUs’ Base Interruptible Program (BIP), including the testing protocols, excess energy charges, notification options (15- and 30-minute options), and incentives. The next follow-up discussion is on June 26 to continue the discussion on BIP and to begin the discussion on the Capacity Bidding Program (CBP).

On May 22, 2018, an Amended Scoping Memo was issued in R.13-09-011 that added the CPUC Energy Division’s evaluation of the DRAM pilots into the proceeding to the existing scope for the 2018-2022 DR Applications (A.17-01-012, A.17-01-018, and A.17-01-019). Because of the complexity and the inconclusive preliminary results from the evaluation, Commissioner Guzman-Aceves wrote in the Amended Scoping Memo that the issues must be addressed in a formal proceeding as opposed to an informal resolution process. In addition to the DRAM pilot evaluation, this proceeding still requires additional time to complete several unresolved issues, including:

• Guidance for pilots to promote DR in disadvantaged communities and transmission-constrained local capacity areas

• Guidance to implement the new automated DR (ADR) incentive policy

• Completing the record with respect to dual participation rules

• Management of and potential changes to the 2% reliability cap

• Final CBP price trigger method

On November 26, 2019, SDG&E submitted a PFM of D.17-12-003 that would allow it to shift DR budget funding amounts across program categories via advice letter. Specifically, SDG&E highlighted how some programs are below what was forecast, causing substantial unspent funds from certain program allocations. In addition, SDG&E has found unanticipated administration and IT expenses related to CAISO market integration.

On May 12, 2020, D.20-05-009 was issued that granted SDG&E’s PFM because it agreed with SDG&E that allowing fund-shifting requests via Tier 3 Advice Letter will provide an administratively efficient path to seek modifications to authorized budgets. The decision explained that the IOUs are in the middle of the first five-year budget cycle and there are claims of unforeseen and unavoidable expenses, such as the growth of third-party DR providers and ongoing changes in the CAISO’s ESDER Initiative.

On April 1, 2020, each of the IOUs submitted advice letters providing their mid-cycle update on their 2018-2022 DR program portfolio. PG&E reported a $39.8 million decline in cumulative DR expenditures for 2018 and 2019. Until further policy guidance is provided, PG&E argued that there is little value in initiating other pilots and argued that its existing Excess Supply Pilot and Supply Side Pilot should sunset after the end of current funding. Meanwhile, SCE reported 3% to 4% year-over-year program enrollment declines for its DR program portfolio (totaling 912 MW in 2019). The Constrained Local Capacity Planning Areas & Disadvantaged Communities Pilot has completed planning and is anticipating launch in Q2 2020. Finally, SDG&E mostly focused on the need to align DR programs with that of other IOUs and proposed to close the Armed Forces Pilot and Overgeneration Pilot due to customer feedback and cost-effectiveness concerns.

Several general comments or recommendations were offered in response. PAO recommended that the IOUs reduce their DR budgets from the approved levels in 2020 and 2021 to the actual 2019 spending level since the programs are unlikely to achieve high customer participation in the near future than in 2019. The IOUs, however, requested that the CPUC Energy Division reject this proposal because there are true-up mechanisms already in place to return unspent funds for incentives. Meanwhile, CEDMC argued that IOUs’ retail CBP and BIP should be revised to exclude PSPS events when calculating performance during a DR event. PG&E disagreed, noting that the CAISO has existing processes for outages to reflect adjusted CAISO baselines when PSPS events are called. SCE argued that PSPS events are not DR events and treating them as such would then cover all service interruptions, while SDG&E argued against making this change due to implementation challenges. CEDMC also argued for assessing the accuracy of a non-residential 5-in-10 baseline with a 40% adjustment cap, holding workshops to develop specific improvements on the technology incentive programs, developing pilots to test shift, shimmy, and shape DR products, and other modifications. The IOUs generally argued that these issues were out of scope or premature.

2018 and Beyond Demand Response Programs

On May 20, 2016, a Ruling sought responses to questions on the Interim Phase 1 Results of LBNL’s 2015 California Demand Response Potential Study, which shares key findings on how DR can meet system and local peak RA capacity needs, including the role that battery storage could play in driving down costs for DR in California. Comments filed by parties will be used to further develop a record to support a decision providing PG&E, SDG&E, and SCE guidance for developing DR applications for 2018 and beyond DR activities and budgets.

See CESA's comments on July 1, 2016 on guidance for 2018 and beyond DR programs.

On September 29, 2016, D.16-09-056 was adopted that provided guidance to the IOUs for 2018 and beyond DR programs. D.16-09-056 resolved and closed Phase 2, while resolving some Phase 3 issues but keeping Phase 3 open. Specifically, D.16-09-056:

• Modifies D.14-12-024 to rescind data collection requirements for fossil-fueled backup generators in DR programs

• Adopts a new goal and set of principles for DR programs that emphasize environmental objectives, customer choice, market competition, performance-based contracts, and cost effectiveness

• Defers the determination of the utility role in future DR programs until there are outcomes of market-driven competition

• Sets initial guidance and evaluation criteria for transitioning DRAM from pilot to full-program status

• Establishes a five-year budget cycle with a 2020 mid-cycle review

Significantly, D.16-09-056 requires that the IOUs establish a new model for fast-response programs to meet future flexible capacity and ancillary service needs, starting with an Application for this newer model to be submitted by October 2018 for a 2020 start date.

Overall, this is a very positive outcome for CESA members. CESA strongly supported the Proposed Decision and offered limited comments on the importance of third-party market competition and in expediting the procedural timeline for guidance on fast-response DR programs. 

See CESA's comments on September 19, 2016 on Proposed Decision for 2018 and beyond DR programs

Reliability Cap

D.10-06-034 adopted the Reliability Cap Settlement.

On March 30, 2018, the IOUs filed a report on the February 14, 2018 reliability cap workshop. The amount of headroom under the 2% (of the all-time system peak) reliability cap is determined on the basis of MW of capacity provided by each existing DR program as calculated annually based on load impact protocol studies and then allocated among the three IOUs. The cap established the maximum amount of RA (not the amount of "reliability" resources) that could count toward the IOUs' RA requirement. With increasing levels of third-party participation, the workshop report noted that there is uncertainty as to whether DRAM participation would count toward the reliability cap if the permanent DRAM is required to submit economic bids in the wholesale market. The IOUs hold the view that DRAM resources receive RA value based on their contract capacity (not their actual MW delivered) while other DR programs are evaluated through load impact protocols that look at historical performance. The Joint DR Parties held a different view that only participation in RDRR is counted toward this cap. If the IOUs determined that they are within 95% of its individually-allocated reliability cap, it will suspend enrollments in either BIP or RDRR. 

The IOUs proposed to allocate any headroom that is available to maximize the ability of existing DR resources to be integrated into the CAISO markets and to do so through "request windows" and lotteries to allow equal treatment of directly-enrolled customers in DR programs and aggregated customers, but with priorities set for resources that would "de-island or address a local need identified by the CAISO. The Joint DR Parties, on the other hand, proposed that availability under the cap be offered first to new third parties that want to aggregate customers to participate in BIP before being offered to customers participating through an IOU. They argued that this policy aligned with D.16-09-056, which expressed the CPUC's "preference for services provided by third parties" at competitively-determined prices. 

On June 15, 2018, a Ruling was issued that posed questions for stakeholder feedback on whether to modify the 2% reliability cap. The Ruling detailed the CPUC’s research that found that RDRR resources are being called upon less frequently and thus posed questions to the stakeholders on whether to adopt additional flexibility in the trigger by allowing its use anytime within the "Warning stage" or even prior to the Warning stage - e.g., Alert notice and/or Restricted Maintenance Operations. In responses, the CAISO, IOUs, and ORA supported allowing dispatch of RDRRs any time within the Warning stage. However, the CAISO did not support greater dispatch flexibility in exchange for re-opening the settlement agreement to increase the amount of RDRRs that qualifies as RA since RDRR bids are not optimized in the CAISO markets unless the CAISO declares a Warning or Transmission Emergency. Specifically, the CAISO noted that RDRRs are dispatched very late in its emergency operating procedure process after exceptionally dispatching non-RA resources.

CLECA, which represents large industrial customers, argued that infrequent use of RDRR should be expected given how the RA construct plans for 1-in-10 conditions and that the CPUC must make a distinction between market-based and out-of-market RDRR dispatches. For market-based RDRRs, CLECA expressed concerns with the trigger for exceptionally dispatching RDRRs before system reliability issues occur given the volatility of the market with the possibility of sudden price spikes, preferring instead to have adjustments to other committed resources before resorting to RDRRs in the market. Overall, CESA believes that the frequent dispatch of RDRRs without sufficient alerts or consideration of alternatives is what is driving CLECA, which may lead to overly frequent disruption of certain customer loads when RDRRs have been dispatched not more than once per year from 2010-2017.

On October 25, 2018, a PD was issued that determined that the 2% cap should remain unchanged, confirmed use of RDRR anytime within the Warning Stage,  and directed the prioritization of third-party customers in the allocation of any remaining MWs under the reliability cap. The CAISO explained that for In-Market dispatch even after the CAISO calls a Warning Stage and the RDRR is made available for In-Market dispatch, the locational marginal price must reach the RDRR strike price before RDRR load is dropped, unless an exceptional dispatch is issued. The CAISO dispatches RDRR very late in its emergency operating procedure process, only after exceptionally dispatching non-resource adequacy resources, despite the fact that RDRR are RA resources. However, due to concerns about the frequency of notices, the PD did not propose to allow RDRR to be triggered prior to the Warning Stage at this time.

Meanwhile, the PD supported third-party prioritization because third parties represent a much smaller share of BIP customers and the CPUC seeks a level and competitive playing field. The PD also adopted a process to calculate the available headroom under the cap as well as the following procedures: (1) the annual LIP report should be the document where the available headroom for the IOUs, both individually and collectively, should be assessed; (2) if the LIP Report indicates one or more of the IOUs has exceeded its cap, the IOU should suspend enrollment of additional MW that will count against the cap; (3) allocation of available headroom should be based on the value of the MW, with MW that can de-island existing megawatts given the highest value and those that would be islanded if enrolled given the lowest value; and (4) MW procured through the pilot auction mechanism count toward the reliability cap.

CESA provided limited comments that, given the limited third-party DR opportunities, it is prudent to allocate the remaining capacity under the reliability cap to third-party resources. In comments to the PD, the CAISO clarified that the PD’s determination would allow the release of RDRR into the CAISO’s bid stack upon declaration of a Warning Stage event, resulting in the RDRR to be available for economic dispatch through the CAISO’s market optimization at a bid price of $950-$1,000/MWh or for exceptional dispatch.

On December 10, 2018, D.18-11-029 was issued without any material changes from the PD. In response to comments to the PD, the decision noted that a complex de-islanding requirement may result in “unintended consequences” including unreasonable costs for a small amount of capacity, and thus declined to adopt this requirement as it relates to the reliability cap. In addition, given that SDG&E is well below subscribing 50% of its reliability cap, the decision determined that SDG&E be allowed to use a first-come, first-served approach until it reaches 50% of its cap to address cost-effectiveness concerns and preserve the desired level playing field.

On June 29, 2020, pursuant to D.17-12-003 that found SDG&E’s DR programs as not cost-effective, SDG&E submitted an advice letter reporting on the cost-effectiveness of its DR programs and its efforts to make mandated improvements. However, no single program in its portfolio was found to be cost-effectiveness subject to the TRC, falling far below a ratio of 1 for all years administered. SDG&E cited the change in the RA hours from 4-9pm and the smaller industrial base as causes for the results. PAO protested the advice letter and called for SDG&E to file an application within 90 days of the disposition proposing significant modifications to its DR programs.

DR Programs in Disadvantaged Communities

On June 15, 2018, a Ruling was issued that posed questions for stakeholder feedback on DR programs in disadvantaged communities. Since existing gas generation capacity is disproportionately located in DACs and because a previous DR potential study demonstrated the potential value of locally-focused DR resources, the CPUC attached a staff proposal to the Ruling for stakeholder comment that would support the creation of new DR programs targeted to DACs (referred to as “DAC-DR” programs). The staff proposal included guidance on DAC-DR pilot plans and established the objective to identify actionable policy recommendations for DR programs through these pilots. Pilot locations were determined based on the proportion of DACs within communities and cities within 20-30 miles of a gas peaker plant and ranked according to CalEnviroScreen’s poverty and pollution burden scores, while granting SDG&E some flexibility in developing DR programs to not target specific locations. The candidate locations include: Huron, Selma, and Fresno for PG&E; Colton, San Bernandino, and La Puente for SCE; and Chula Vista and National City for SDG&E. Budgets for these pilots as authorized under D.17-12-003 would be $1 million each for PG&E and SCE and $0.5 million for SDG&E.

Only SDG&E opposing the staff proposal as being too prescriptive for a territory like that of SDG&E while being skeptical on the attainability of the goals. Otherwise, all other parties supported the staff proposal with a few key recommendations for improvement or modifications. SCE proposed a specific pilot to replace existing heat pump water heaters powered by fossil fuels with DR-enabled electric water heaters. PG&E proposed a pilot concept of an environmental DR program. Many of the third-party DR providers (Nest, Ecobee, Olivine, OhmConnect), meanwhile, favored using existing DR programs and cost-effectiveness methodologies to focus participation on DAC customers and supporting third parties through access to customer data and additional value and compensation (e.g., environmental value, RA capacity). Common recommendations among all parties were also offered to study barriers to customer participation, develop more concrete and measurable outcomes, take advantage of synergies with energy efficiency program participation, customize event and outreach messaging, and broaden the locational requirement to local capacity areas (LCAs). PG&E and ORA, on the other hand, noted one reservation about whether DR resources targeted in DACs would equate to reduced or avoided dispatch of fossil-fueled generation located in the DAC due to scale or technical power flow reasons.

On December 10, 2018, D.18-11-029 was issued that established guidelines for pilots targeting residential and small commercial customers residing in DACs. The guidelines would consider supply-side DR programs and direct the development of new and innovative program designs. The decision also adopted the use of Olivine’s proposed locations, the test objectives from the CPUC’s Staff Proposal, and an advice letter process for submittal and approval of the pilot proposals.

DR Program Alignment

On June 26, 2018, a meeting was held on to discuss possible areas of alignment for the IOUs’ BIP programs, including around 15-minute notification options, testing protocols, excess energy charges, and incentives. Stakeholders generally agreed that BIP incentives would be difficult to align across the three IOUs because the incentives are paid based on the avoided cost benefits attributed to the load impacts of DR responses, as well as administrative and overhead costs of implementing the program – both of which likely vary by IOU. For similar reasons, excess energy charges were determined to be a non-ideal candidate to align across the three IOUs. CLECA and CPower put forth proposals to consider aligning pre-enrollment testing and retesting protocols that assess and re-assess the firm service level (FSL) of a customer to determine the DR response amount. PG&E was considered a best practice to which the other IOUs could align, though the multiple retest requests by PG&E protocols that would potentially force a customer to de-enroll, increase FSL, or incur excess energy charges was highlighted by CPower as an improvement area. SCE noted that they do not have such protocols but plan to model their protocols after that of PG&E. Finally, CLECA proposed that both PG&E and SDG&E consider developing a 15-minute notification option modeled after SCE. These proposals will be included for discussion in their filing on the 2018-2022 DR program mid-cycle review.

On August 7, 2018, a meeting was held to discuss improvements in alignment and consistency of CBP parameters and protocols. Potential areas for improved alignment included dispatch options, dispatch notification and event-hour windows, enrollments dates and forms, and minimum bid requirements of 100 kW.

On September 12, 2018, stakeholders considered the differences in CBP program parameters and protocols and discussed potential alignment proposals. Stakeholders first focused on day-ahead versus day-of dispatch options. Though no formal alignment proposal was made, a preference was expressed to align the IOUs’ CBP programs around offering both options but to also maintain current options for dispatch windows (event hours). For the day-ahead option, stakeholders also recommended alignment on a common notification time. Next, regarding the program season and enrollment, stakeholders discussed how the IOUs should align on year-round seasons and use the same enrollment platform provider, if possible. Finally, the group discussed some of the challenges around LSE-specific criteria for the 100-kW minimum bid in CBP, which is a greater challenge for PG&E’s program due to the larger number of LSEs and sub-LAPs. However, with the expected PDR product rule changes, this issue should be resolved prior to the 2020 DR program year.

On December 10, 2018, D.18-11-029 was issued that determined that the open season for BIP will remain in November (rather than to April) to more closely align with the release of the Load Impact Protocols (LIP) Report in April of each year. The rules of the open season are also modified to only permit disenrollment and decrease in participation of DR of existing customers. In the same decision, the CPUC approved SDG&E’s proposed CBP price trigger established using the Opportunity Cost Method, especially given that the CPUC has previously found that the trigger based on energy price (rather than heat rate) to be reasonable and SDG&E has submitted filings explaining its method accordingly. The Opportunity Cost Analysis Method is defined as a way to identify a minimum price trigger that relies on targeting a pre-specified number of economic event hours within the respective program maximums, such that events would remain available for reliability purposes.

CAISO Wholesale Baselines

On October 24, 2018, the IOUs filed a joint notice of FERC approval of the wholesale baselines submitted by the CAISO,. The new baselines include weather-matching and control group methodologies that were developed in Baseline Analysis Working Group of ESDER Phase 2.

On January 3, 2019, the IOUs issued prehearing conference statements to determine whether to revise the baselines accordingly for the utility-run DR programs as well. Each of the IOUs indicated that evidentiary hearings would not be needed and instead a workshop and commenting process would suffice. SCE expressed how it is unclear how applicable the BAWG baselines are to utility-run DR programs given the following issues:

• The FERC-approved baselines apply at the aggregate level and has not been studied to be used at the disaggregated level.

• There is no resolution around whether the same baseline for wholesale settlement should also be used for retail settlements (i.e., interplay between retail and wholesale baselines).

• It is unclear whether each customer would have the choice of baseline, or whether the IOU or aggregator would play the role of choosing the baseline option.

PG&E raised similar issues to be scoped in but also added their concern about the administrative complexity of allowing multiple baseline options and thus recommended limiting the number of options.

DR Measurement, Evaluation, & Verification Plans

On June 1, 2018, SCE filed an advice letter that published its five-year plan for conducting measurement, evaluation, and verification of its 2018-2022 DR programs. Specifically, SCE detailed how it will conduct its annual load impact studies and how it will perform process evaluations that will identify program design and delivery improvements for selected programs in its DR program portfolio. The CPP and SDP are some of the programs identified as potentially benefiting from process evaluations, which are not conducted on an annual basis, because significant design modifications that occurred since their last process evaluation during the 2012-2014 cycle. These study plans do not include DRAM or energy storage enabled DR, such as through the LCR and PRP agreements.

Base Interruptible Program (BIP)

On June 14, 2019, SDG&E submitted an advice letter that proposed a number of enhancements and clarifications to the tariff. Importantly, given the small number of large C&I customers in SDG&E’s territory, SDG&E proposed to reduce the minimum committed load of 1 MW for aggregation participation in BIP down to 100 kW to encourage greater aggregator participation. Additionally, SDG&E clarified that the firm service level of any customer cannot be less than zero, which has the effect of not counting customer usage below zero in the case of battery storage in the baseline calculation.

On April 1, 2020, in its mid-cycle update advice letter, PG&E proposed to modify the eligibility requirement for the BIP from 100-kW maximum demand to 100-kW average demand during the peak TOU hours in the previous 12 months: While this impacts certain participants with seasonal load, a majority of participants during 2018-2019 BIP events had load below their Firm Service Level (FSL) before the start of an event, suggesting “peaky” rather than consistent loads with the potential for load reduction when events are called upon. There is no mechanism for ensuring that there is a probability that participants drop load during a BIP event. PG&E also proposed to modify Excess Energy Charges for BIP participant underperformance: PG&E proposed a claw-back option requiring a BIP customer to pay back a portion of its incentive payment using a to-be-determined formula, or a pass-through of any CAISO energy market charge when BIP customers underperform.

In protests, CLECA and CEDMC opposed PG&E’s BIP eligibility changes on procedural grounds as well as for reducing customer enrollment. CEDMC added that PG&E’s proposed solution would not resolve the need for 24x7 emergency capacity, noting that loads are typically not consistent and that underperformance should reflect the commensurate harm from BIP participation. Due to the need for a more collaborative approach, PG&E offered to suspend this proposal to develop an alternative eligibility requirement.

On April 1, 2020, in its mid-cycle update advice letter, SDG&E proposed to update the BIP measuring hours for monthly average peak demand would shift from 1-6pm to 4-9pm to reflect the latest availability assessment hours.

Capacity Bidding Program (CBP)

On November 15, 2018, the IOUs filed advice letters that proposed methodologies for updated price triggers pursuant to Resolution E-4918, which directed the IOUs to reduce the impact of outlier prices on CBP trigger mechanisms. PG&E performed harmonic means analysis to achieve five economic events during an operating month, which led it to propose a new $95/MWh trigger price (up from $85/MWh). SCE described how it used the price filtering method that resulted in significantly reduced number of day-ahead market events for the higher trigger prices in October to May, but it did not reduce the number of day-ahead market events for June to September or the number of real-time market events for any trigger price. Using the opportunity cost analysis methodology, SCE developed the following proposal for updated trigger prices.

Unlike the two other IOUs, SDG&E did not propose a methodology for reducing the impact of outliers in the data and instead proposed to allow for more flexibility by which the program is dispatched. Specifically, SDG&E proposes to slightly increase the price trigger from $74/MW to $80/MW for the CBP day-ahead 11am-7pm and 1pm-9pm product options, since prices are generally increasing year-over-year. For the CBP day-of 11am-7pm and 1pm-9pm options, SDG&E proposes to maintain the current price triggers of $95/MW and $110/MW, respectively, because the increase in real-time prices from 2010-2018 was much small than for day-ahead prices. SDG&E plans to mitigate the impact of outlier months by adjusting the price trigger to be dispatched for the four highest price days of that month and to avoid exceeding program limits (maximum of 24 hours per month).

On December 20, 2019, SCE proposed four changes to its CBP tariff:

• Shift the dispatch window to encompass the RA Availability Assessment Hours (AAH): SCE proposed to shift the current six-hour dispatch window from 1-7 pm to 3-9pmto be more in line with current AAH.

• Change day-ahead (DA) event notifications: SCE proposed to change the DA event notification from the previous business day to the previous calendar day. This change will allow SCE to notify customers the next calendar day avoiding impacts on Fridays and holiday weekends and ensures that DA events reflect market awards, rather than those on Mondays and days after holidays being based on forecasted prices.

• Modify the CBP Capacity Payment Band: SCE proposed a change to the formula to match that of PG&E and SDG&E to assess penalties on delivered capacity that is less than 60% of nominated capacity (instead of less than 50%), as follows: (Capacity Rate) * [Delivered kW – 0.6 * (Nominated kW)]

• Add new marketing requirement language to the CBP aggregator agreement: This is intended to ensure third parties do not use SCE’s name and logo in communications without their expressed approval.

On March 4, 2020, PG&E submitted a supplemental advice letter to allow for electronic enrollment to facilitate residential enrollment into CBP as part of a pilot, leveraging an upgrade to its IT system. If successful, PG&E indicated that it could convert electronic enrollment as a permanent option in the 2022-2026 DR applications.

On April 1, 2020, in its mid-cycle update advice letter, SCE proposed to expand CBP to residential customers. Instead of waiting for the pilot phase, SCE proposed to allow residential customers to enroll due to lower implementation costs. Furthermore, instead of performing an evaluation at this time, SCE proposed moving forward with inclusion of a 5-in-10 baseline to SCE’s CBP tariff. Finally, SCE’s analysis found that the May-October and November-April day-ahead market triggers should be increased from $75/kWh to $80/kWh and from $65/kWh to $75/kWh. For administrative efficiency, SCE proposed $75/kWh as the year-round price trigger.

In protests, CEDMC recommended that SCE align BIP minimum load eligibility to be consistent with PG&E (instead of SCE’s current 200-kW monthly maximum demand threshold), adopt the $80 summer and $75 winter price triggers instead of year-round $75 price trigger, and offer a CBP Elect product similar to PG&E that allows for differentiated hourly bids. SCE disagreed and found that customers have not expressed any issues and how additional changes would require additional funding.

On April 1, 2020, in its mid-cycle update advice letter, SDG&E proposed to shorten the CBP Day-Of notification time to 40 minutes prior to event; SDG&E argued that this would align the notification times of all IOU CBP programs. SDG&E also detailed the baseline analysis that will be conducted with 5-in-10 baseline option to SDG&E’s CBP tariff option.

Automated Demand Response (ADR)

Background

The ADR Program provides customer incentives to emerging and enabling technologies to install automated technologies that allow automated response to a DR event or price signal without the customer taking an action (i.e., qualifying energy management control systems that can respond to signal from a DR Automation Server). Eligible technologies, equipment, processes, and products include energy efficient devices, energy storage, EV charging stations, and controls that interoperate using generally-accepted industry open standards or protocols. The program currently uses a $200/kW incentive level and calculates the incentive amount based on a building end-use load shed test, with the customer eligible for incentives up to 75% of the project cost, if their building performs adequately. A condition of incentive payment is to participate in one of qualifying DR programs (e.g., CPP, AMP, CBP, DRAM). Battery storage is eligible if used for DR event participation only, according to SCE. The IOUs generally argue that LCR contracts and SGIP-funded projects are not eligible for ADR incentives.

ADR Guidelines

On February 20, 2018, the IOUs filed a set of proposed guidelines to implement the ADR incentive policy adopted in D.17-12-003. The policy requires that the IOUs provide ADR technology incentives to participants of any supply-side DR program or activity that is not required to be analyzed for cost-effectiveness (i.e., pilot). 

On April 20, 2018, a teleconference was held in accordance with D.17-12-003 that directed the IOUs to file a set of draft guidelines that clarifies the undefined aspects of the ADR device policy, including eligibility frequency and eligible devices and whether ADR incentives are intended for all supply-side DR programs and subject to other CPUC policies (e.g., cost-effectiveness, MUA rules, and competitive neutrality cost causation principle). Each IOU reviewed each of their draft guidelines documents and sought common understanding with parties on definitions and guiding principles. Parties voiced no objection to the definitions, background, purpose of the guidelines document, or the guiding principles proposed by the IOUs. CESA was active in these discussions as some of the IOUs are considering ineligibility for both ADR incentives and LCR contracts, a critical barrier to MUAs for BTM energy storage resources.

On May 8, 2018, an in-person workshop was held to continue discussions on the guidelines for implementing the ADR incentive requirement. The workshop began with clarifications on terminology and criteria for controls eligible for ADR incentives. Parties developed the following definition of an ADR control: "the ability to receive an automated DR signal to enable the customer to participate in a DR event for current models of DR without any manual customer intervention". Parties also agreed on one requirement for controls in all three classes of customers: "the control must be able to receive an Open ADR compliant ADR signal". The IOUs believe that either BTM energy storage systems do not qualify as an eligible technology for ADR or that ADR-funded energy storage systems would be ineligible for SGIP incentives, LCR contracts, or participation in other DR programs. For LCR contracts where all costs are included in the bid, the IOUs expressed several concerns how allowing ADR eligibility would result in ratepayers paying twice for the same product (contract + ADR incentives), how the incentive for the control should be calculated, how the resource can be ensured of being available when called, and how settlement is done for two resources that operate behind the same retail meter. AMS contended that these issues overlap with the issues of dual participation. 

Discussions in the workshop then shifted to customer choices for receiving ADR incentives and cost-effectiveness analysis of ADR incentives, which ORA pointed out has been excluded in the evaluation of DR programs. Parties agreed that because the BIP is a reliability program and is subject to a cost-effectiveness analysis, it is not applicable to the newly adopted ADR incentive policy, and that the CPUC did not establish a requirement that the IOUs must provide ADR control incentives for supply-side programs subject to cost-effectiveness analyses. The IOUs also developed a matrix of the programs to which they consider the ADR incentive policy applicable. 

On May 23, 2018, the IOUs responded to the CPUC data request to help them understand which DR programs and pilots are eligible for participants to also receive ADR incentives. The IOUs clarified that CBP and DRAM participants are all eligible to receive ADR incentives, with selective eligibility for certain IOU customers on CPP rates. The IOUs observed that no ADR program has funded incentives for battery storage controls and only one IOU has received an application from an energy storage provider. The IOUs also noted that battery storage systems should already include controls and communications to automatically manage the frequent charge and discharge functions of the battery, which are also costs that should be eligible for SGIP incentives.

On June 15, 2018, a Ruling was issued that included a number of questions related to the eligibility of resources receiving ADR incentives to participate in other DR programs, as well as in DR contracts and SGIP incentives external to the DR programs and portfolio of the IOUs. CESA argued that eligibility of ADR incentives with battery storage systems should apply for all types of supply-side DR and that deeming a whole LCR or SGIP project as ineligible for ADR incentives is unreasonable as the ADR incentive should be allowed for the eligible control portion of the energy storage resource. Specifically, CESA noted that LCR contracts and SGIP incentives may not fund ADR-compliant controls and recommended that the ADR Program could report specific line item or component costs for the eligible controls needed to achieve ADR compliance - similar to how eligible equipment costs are reported for SGIP and SGIP incentive payments are adjusted based on other funding sources.

See CESA’s response on July 20, 2018 on the ADR Ruling

Other parties also filed responses. Many DR providers sought to broaden eligibility for ADR incentives to controls that enable response to ‘signals’ more broadly and to avoid specifying a communication protocol (e.g., SDG&E favored broadening the eligibility definition to include “connectivity to the manufacturer’s cloud” for ADR incentives), while PG&E and SCE generally favored not just ADR compliance but ADR certification. Due to the infrequency of dispatches, PG&E and ORA opposed ADR incentives being made available to RDRR resources. While SDG&E did not support the ADR incentive eligibility for LCR/DRAM contracts, PG&E held the view that the incrementality and compensation decision should be made on a case-by-case basis. PG&E, SCE, and ORA also made the case for adopting a flat or fixed incentive level for ADR controls since the current incentive structure is based on a load shed test that may result in overpayment. CESA responded to these comments by stating that energy storage resources should not be subjected to different formulas for calculated ADR incentives and that overcompensation of energy storage resources receiving ADR incentives can be avoided by appropriate disclosure of line cost items.

See CESA’s replies on August 3, 2018 on the ADR Ruling

On October 25, 2018, a PD was issued that proposed to adopt a new ADR control definition and ADR policies to be included in the revised ADR Control Incentives Guidelines and Adopted Policies. CESA commented on the PD that energy storage systems should be eligible for ADR control incentives and the stakeholder process is reasonable.

See CESA’s comments on November 14, 2018 on the Proposed Decision

On December 10, 2018, D.18-11-029 was issued without any material changes from the PD. ADR control is now defined as: “The ability to receive an automated demand response signal to enable the customer to participate in a demand response event without any manual customer intervention. We note and recognize that many controls either allow or require the customer to acknowledge the signal before it begins equipment shutdown and that customers have override authority when a signal is received.” Notably, email or text communication in addition to an automatic signal does not disqualify a customer from ADR control incentives. In the revised ADR Control Incentives Guidelines and Adopted Policies, the decision concluded the following:

• Neither requiring or prohibiting ADR control incentives for supply-side DR programs

• Not allowing RDRR resources to be eligible for ADR control incentives, tracking incremental load reduction provided by ADR controls

• Not considering ADR a “program” that could be developed by CCAs under the Competitive Neutrality Cost Causation Principle (i.e., the decision distinguished ADR as an incentive program that is neither a load-modifying or supply-side program, but to enable participation in those programs)

• Requiring controls to be Open ADR 2.0 compliant and located onsite or at the cloud level for residential and small business customers

• Requiring controls to be Open ADR 2.0 compliant, located onsite for commercial and industrial customers, and verifiable by IOU for anticipated kW load drop

• Requiring deemed incentive to be based on average kW load drop for control in the small or medium business customer sector for such customers

The decision punted on issues related to the frequency of ADR control incentives and calculating incentives cost-effectiveness to a separate annual IOU proposal process on April 1 of each year. For DR resources procured outside of the IOU portfolio, the decision decided to have ADR incentives be a contract term and thus determined such resources to be ineligible for ADR control incentives. Furthermore, the decision adopted a stakeholder process to pursue further technical refinements to the adopted guidelines, including developing an overall strategy proposal for battery storage controls that concludes in an ADR Battery Storage Stakeholder Report.

On January 10, 2019, an initial stakeholder meeting was held to address questions about ADR and battery controls, pursuant to D.18-11-029. Industry representatives Some of the key fundamental questions include:

• What controls do batteries come with when they are manufactured that allow them to communicate with entities using them for demand charge and TOU management? What does SGIP provide in the way of controls?

• Are batteries ready and able to participate in DR programs, and if so, how? If not, why not?

• What do battery manufacturers and industry stakeholders need from the ADR program, and why?

The objective of this conference call was to familiarize stakeholders with the SGIP program and Title 24 update requirements for DR controls and their intersections with the ADR programs to address fundamental questions about battery storage controls. In presenting on the state of ADR controls, the CPUC was seeking information on what battery installers need from the ADR program. CSE, one of the SGIP PAs, presented on how the program does not have any requirements on what controls or communication platform systems to use, as there are no requirements that SGIP-funded energy storage systems be able to respond to external signals. The type of controller and communication platform does not impact the incentive calculation, which is based on energy rating and capped at 100% of eligible system costs. Two energy storage systems with the same energy rating would get the same incentive regardless of whether one had an OpenADR-certified controller. The system controller is assumed to be included in either the “capital costs” or “electricity storage device” among the eligible project costs. SGIP can cover the cost of communications and controls, but there is no program requirement for participants to use the funds for that, and there are no specifications on eligible controls if they do. SGIP doesn’t keep records at a level of detail to show which projects used their incentive for controls. At this time, SGIP covers about 41% of a project’s cost on average, CSE reported. When a SGIP customer is enrolled in a DR Program, SGIP counts the battery discharges that are made for a DR program event toward the annual required total. Furthermore, beginning January 1, 2020, the Title 24 building code will require all residential battery installations to meet a list of requirements, including the ADR control requirement to qualify with applicable performance compliance credit. The ADR control requirement would require the control to be OpenADR certified on site or at the cloud.

Select industry representatives were also on the call to help the CPUC understand what controls and communications come with battery storage when installed and how they work for customer bill management (i.e., automated response, OpenADR interoperability). The battery integrators on the call discussed how they do not necessarily need any ADR control or communications incentive to participate in DRAM or in IOU DR programs since they manage batteries from their clouds. Battery integrators on the call discussed how they are primarily interested in value stacking to achieve a better cost-benefit ratio for energy storage and are less concerned about any incentives for controls and communications needed for DR programs, which would only make DR program participation slightly more attractive.

On January 31, 2019, the first stakeholder meeting was held to discuss the battery integrators’ and IOUs’ positions on the need for control incentives for battery storage. The CPUC staff discussed how the ADR Control Incentives Program had not originally contemplated battery storage since they generally manage their assets from the cloud to aggregate smaller loads. The IOUs also suspected that battery storage providers would likely not want utility control of the asset as part of receiving the ADR incentive. There is still a lack of clarity on whether a battery’s energy management system (EMS) could qualify for ADR incentives, which is an area that CESA sought clarification. Otherwise, even though it looks like battery storage may not be a good fit in this program, given the burdensome requirements (e.g., utility control, evaluation, reporting) relative to the small cost of ADR controls and small incentive amount, CESA pushed for the final report from the IOUs to instead broadly focus on the barriers of DR program participation from battery storage resources.

On April 15, 2019, the IOUs published a final report providing an update on battery storage participation in ADR programs. The IOUs stated that they do not support offering ADR incentives for battery storage controls since stakeholders indicated that they preferred changing rate structures and DR program designs over a change in ADR guidelines and because battery manufacturers and integrators are already equipped with ADR-like controls. Given the challenges of isolating the incremental or ADR-only portion of costs and avoiding double payment, the IOUs supported prohibiting battery storage from accessing ADR incentives.

On May 1, 2019, each of the IOUs submitted their annual ADR process proposal where objectives are revised so that technologies such as battery storage, EV charging stations, and smart thermostats are not deemed eligible for ADR incentives, since they already come with controls with automated communication capabilities to support receiving and acting upon DR signals. For ADR incentive amounts, while PG&E and SDG&E proposed changes to their current 60/40 model, SCE proposed to maintain their current ADR Program structure until 2021:

• PG&E proposed an ADR incentive equal to 15% of eligible ADR control costs for the non-residential sector and a deemed ADR incentive based on the average market cost of an eligible ADR control, starting in 2020. PG&E argued that this percentage-based methodology would eliminate costly engineering calculations and thus diminish the program’s administration burden.

• SCE proposed to maintain that 60% of the ADR incentive is paid upon installation and verification of the load reduction and 40% is paid based on DR performance in the first year. Instead, SCE recommended that the incentive structure should be evaluated. In their view, a deemed dollar per device approach may be easier for customers to understand and may help ADR implementors with more accurate cost-benefit analysis.

• SDG&E proposed to pay an incentive of $67/kW for installation and then an incremental performance payment of $67/kW per year for the next two years based on performance verified by SDG&E.

In addition, a number of other details were proposed:

• Frequency of existing incentives: PG&E proposed to set the frequency of existing ADR control incentives to 7.5 years based on technology useful life. SDG&E proposed that the duration of the incentive should be consistent with the amortization period used in the cost-effectiveness test. SCE proposed to base the duration based on the technology useful life and the period of the cost-effectiveness test.

• DRAM eligibility: PG&E proposed a continuation of the policy that ADR program incentives cannot be used for RDRR resources in the DRAM, while SDG&E proposed ineligibility of ADR program incentives for all DRAM resources due to firewall restrictions. SCE proposed both ideas, which depended on the solution.

• Incentive cost-effectiveness: PG&E proposed to revisit the calculation for cost-effectiveness given the challenges in attributing incremental load reduction to the ADR controls and the need to include other costs such as program administration beyond just the incentive costs. SCE and SDG&E proposed to include incentive amounts as capital costs in DR program cost-effectiveness tests.

Generally, PG&E recommended that the CPUC revisit the ADR Program objectives since technology manufacturers are already starting to incorporate automated communication capabilities into their technologies. SCE also highlighted how there is reduced customer participation in its ADR Program in recent years.

On June 4, 2019, a workshop presenting the IOUs’ proposals was held as part of the first year of the annual ADR review process to resolve the following issues related to their ADR programs:

• Review of the approach to calculate control incentives

• Implementation of the policy that RDRR are not eligible to receive ADR control incentives

• Determination of the frequency of control incentives

• Calculation of incentive cost-effectiveness

• Development of a list of residential ADR-enabled end-use devices to be considered by PG&E for eligibility for an ADR incentive

• Development of criteria to determine the order for PG&E to evaluate load impacts attributable to the devices

Each of the IOUs highlighted the low participation levels of customers in their ADR programs, while PG&E highlighted the need to potentially assess whether other technologies need ADR incentives – similar to the process undertaken for battery storage resources – given that many technologies use low-cost cloud-based solutions. While a bit out of scope, broader policy questions were raised by CESA and PG&E on the purpose of ADR incentives as a technology incentive or as an enrollment incentive, given that many technologies may already have cloud and communication capabilities and may generally have lower equipment costs.

On July 12, 2019, D.19-07-009 was issued that proposed to maintain the current ADR policy that battery storage controls are not eligible for ADR incentives. The PD justified this determination based on workshops and IOU reports submitted on how battery storage providers are not interested in ADR incentives and how there are challenges related to determining the incremental portion that may not be funded through other programs. On the ADR issue, the decision was unchanged from the May 31, 2019 PD, which CESA responded to by arguing that a path to potential eligibility for ADR control incentives for new technologies is needed to streamline access to these incentives as new technologies emerge.

See CESA’s comments on June 20, 2019 on the Proposed Decision

On September 3, 2019, the IOUs submitted an advice letter that proposed the following resolutions to the technical issues included in D.18-11-029:

• No changes are proposed for the calculation of control incentives until further research is performed and completed.

• Since D.19-07-009 excluded RDRR from DRAM, the IOUs discussed how they no longer need to develop a proposal to ensure control incentives do not go to RDRR.

• Customers should be eligible for ADR incentives once every 7.5 years for controls of the same end use but may receive another incentive before the 7.5-year time period elapses if ADR controls are unable to communicate and receive DR signals due to changes in communications protocols.

• ADR incentives should be allocated in line with the forecasted load reduction with new ADR participants in each program.

• ADR incentive costs will be allocated to ADR-eligible programs based on a forecast of the cumulative incremental ADR-enabled kW in each eligible program over the program cycle, multiplied by the estimated $/kW incentive for that program.

PG&E noted that it will resume stakeholder processes and conduct further research on developing a list of residential end-use devices to be considered for eligibility for the ADR incentive.

ADR Program Refinements

On March 27, 2020, Opinion Dynamics, on behalf of PG&E, published a final report sharing the results of the assessment of control technologies that were submitted in response to its RFI for the PG&E’s residential ADR program. PG&E launched this study to potentially expand the list of technologies that qualify for rebates under its 2020-2022 residential ADR program. The focus was on automated control technologies for the residential sector that leverage the standard of OpenADR to support customers on DR programs. The study team received control technology applications from 14 manufacturers, ranging from AC and plug-load controls, AI-based energy management platform, energy management automation control system devices, EV charging control, smart thermostats, and water heater controls.

Based on the combined assessment, Opinion Dynamics did not recommend any of the final candidate technologies to the current OpenADR program due to a lack of demonstrated field testings of OpenADR communications from the utility down to the end device, and/or because of insufficient experience implementing controls at a utility-scale comparable to PG&E’s service territory. However, the team recommended that PG&E begin two technology demonstrations with water heater controls and EV chargers through the Demand Response Emerging Technologies (DRET) Program. In addition, despite the lack of OpenADR compliance at the end-use device level, Opinion Dynamics highlighted the potential of leveraging aggregators with OpenADR communication abilities. While single end-use devices can provide reliable estimates of the expected control impacts and be incorporated into the current program with minimal changes in program design, multi end-use home energy management systems could offer the advantage of aggregating demand impacts in a consumer-friendly manner with less need for PG&E to evaluate each end-use technology.

The conservative conclusions from the study were disappointing in that promising EV charging control and water heater control technologies were largely screened out due to PG&E’s preference for technologies with large-scale deployments numbering in the tens of thousands, not those that only have a history of field trials numbering in the hundreds. This was despite the positive references regarding their utility pilots and the consultant recognizing the load-shifting potential.

On May 1, 2020, the IOUs jointly submitted a technical proposal to identify a new approach to calculate ADR incentives for non-residential customers. To this end, the IOUs jointly proposed to adopt a new deemed incentive structure design for the non-residential ADR Program. To support this design, PG&E, who is leading this effort, will explore different options, including one based on technology costs, end-use load flexibility, enrollment, manufacturer, or distributor. Upon completion of the study, the IOUs will submit the research results and detailed proposal in an advice letter on September 1, 2020.

Customer Data Access

Click-Through Process Authorization

On August 25, 2017, Final Resolution E-4868 approved, with modifications, the click-through authorization processes proposed by the IOUs that streamlines, simplifies and automates the process for customers to authorize the Utility to share their data with a third-party Demand Response Provider (DRP). Currently, third-party DRPs are authorized to receive customer data from the IOU through a paper or PDF version of the Customer Information Service Request Demand Response Provider form (CISR-DRP Request Form) that the customer signs and the IOU verifies for the customer’s identity – a time consuming and complex process. By contrast, a click-through authorization process enables a customer to authorize the IOU to share the customer’s data with a third-party DRP by completing a consent agreement electronically. The approved click-through authorization process includes:

• Expanded dataset that customers may authorize the IOU to share with third-party DRPs

• New website for reporting real-time or near-real-time performance metrics that are consistent across the IOUs

• Flexibility in the click-through design to accommodate any future expansions of the function

• Various technical and functional specifications, such as timelines for delivering the data and using alternative authentication measures

The Final Resolution also forms a stakeholder Customer Data Access Committee (CDAC) to address ongoing implementation issues. Overall, this is an important development for DRPs given that it makes it easier and quicker to enroll customers, smartly offer DR services using this customer data, and settle bids for CAISO wholesale market participation. The IOUs have until April 2, 2018 to implement Phase 1 of the click-through authentication and authorization process to ensure that the process is ready in time to help increase enrollments in third-party DR provider programs and to support 2018 deliveries in the DRAM program. The IOUs have modified their Rule 24 tariff to implement a new click-through functionality for customer data access and to reflect a new Customer Information Service Request for Demand Response Providers (CISR-DRP) form. 

On October 26, 2018, Resolution E-4914 was issued that approved SDG&E’s click-through authorization process, including its electronic mail notification, an expanded data set, a shorter data set within ninety seconds, and a funding request of up to $800,000 to incorporate the updated CISR-DRP Request Form into the online process.

On May 17, 2019, Resolution E-4974 was issued that approved PG&E’s proposal for the scope and definitions of performance metrics to be put on a public website and for the customer online click-through authorization process to allow PG&E to release energy-related data to a customer-designated third-party DRP.

Customer Data Access Committee (CDAC)

On April 19, 2018, a CDAC meeting was held to discuss Phase 1 solutions to allow third parties to access customer data while ensuring that they do not store customer credentials and mitigating actions of bad actors. SCE proposed a two-factor authentication process but raised technical considerations around cyber protections – e.g., how the IOUs will know whether the customer did not authorize the release of data and which categories of data were authorized. In response, PG&E and SCE recommended that they be indemnified for the Phase 1 solution functionality and that third parties track their system performance.

On June 20, 2018, a CDAC meeting was held that continued discussions and provided a ‘deep dive’ on the requirements for Phase 1 solutions, including ID validation, authentication vulnerabilities, and user interfaces for authorizing access to customer data. OhmConnect also presented on Phase 3 solutions improvements that would provide more granular details and further streamline the process for third-party DR providers. PG&E is in the process of analyzing the feedback received on Solution 1, enhancements to Solution 3, and the DER whitepaper.

On September 20, 2018, during the CDAC meeting, each of the IOUs discussed their enhancements to the customer and data access portals. There were a number of enhancements discussed, including SDG&E’s Outage Communication Plan to customers and PG&E’s Expanded Data Set. Some energy storage providers requested machine-readable tariffs, service voltage information, and billing cycle information to configure energy storage systems and better target customers, which the IOUs generally responded as saying they already do. DR providers requested that the enhancements also include information on whether customers are enrolled in conflicting DR programs and description of the disenrollment process. Many of these enhancements are technical implementation and user interface details requested by energy storage and DR providers to support ease of access to data and improve customer experience.

On December 11, 2018, a CDAC meeting was held that provided the IOUs’ update on Phase 3 launch and discussed PG&E’s advice letter to increase Rule 24 capacities up to the 200,000 registration level. PG&E determined that the increase in Rule 24 registration capacities was needed to support the 2019 DRAM pilot and sustained growth in third-party direct participation.

On March 29, 2019, a CDAC meeting was held to provide updates on the Phase 3 launch and to discuss the customer authorization process from click-through or CISR-DRP through the DRP’s registration of the customer location at the CAISO as well as the IOU-DRP process to resolve instances of missing data, data quality concerns, and gaps in data.

On June 27, 2019 a CDAC meeting was held where OhmConnect presented on several ongoing issues, including failed data sharing authorizations (e.g., lengthy click-through outages and insufficient explanation for the outages), data availability and delayed transfer, poor user interface design (e.g., slow mobile pages), and low customer confidence in customer support and process.

On March 10, 2020, CALSSA presented on customer data access issues at the Interconnection Discussion Forum (IDF) call held, where solutions are sought, particularly with SCE’s system, around fixing customer data authorization rules to support customer acquisition and the determination of accurate savings estimates, especially as the CPUC contemplates adopting a solar bill savings calculator. The IOUs responded that there are API-based portals available, such as Green Button Connect, that are designed for DR customers to access 13-month or 36-month historical interval data. The IOUs also highlighted how there are pending applications seeking funding to expand their click-through platform capabilities.

Click-Through Process Applications

Background

On November 26, 2018, each of the IOUs submitted applications pursuant to Resolution E-4868 to provide cost estimates and additional proposals for improvements to the click-through process, including expanding click-through to other types of DER providers beyond DR resources and providing quick-response data delivery. The IOUs, however, generally did not propose to implement every enhancement that was cost estimated in the applications. In response to problems encountered with web metrics vendors, PG&E requested and was subsequently granted an extension to January 31, 2019 to build the click-through web metrics functionality that will measure aspects of the customer authentication and authorization experience. This functionality was originally required to be implemented by November 26, 2018.

On May 27, 2020, a Scoping Memo was issued, after more than a year of inactivity, that identified the scope as covering the reasonableness of the click-through enhancements proposed by the IOUs, their compliance with Resolution E-4868, and compliance with current CPUC privacy rules. CESA is a party in these consolidated applications and is seeking to expand the applicability of click-through enhancements to all DERs, including storage. After evidentiary hearings, a final decision is expected by Q1 2021.

Demand Response Auction Mechanism (DRAM) Evaluation

Background

On September 29, 2016, D.16-09-056 established initial guidance and evaluation criteria for transitioning the DRAM from pilot to full-program status. The CPUC envisioned utility administration of the DRAM as the primary means for sourcing DR in the future. The new guidance for DRAM included:

• Capping programs at 2017 budget levels until 2020

• Prohibiting utilities from participating in the auction

• Establishing the same RA Availability Incentive Mechanism (RAAIM) penalty for DRAM contracts as for RA contracts

• Establishing DRAM contract lengths of 1-5 years

• Maintaining a 20% set-aside for residential customers

• Limiting the size of DRAM based on the competitiveness of bids received, with the utility required to accept all complying bids up to the simple average August capacity bid price

• Utilities do not have to procure more than 1 GW statewide annually, and do not have to accept bids greater than long-term avoided cost of generation

If DRAM were to move to a permanent mechanism, the decision also discussed how DRAM contracts should be subject to the same rules and penalties as conventional non-DRAM RA contracts. The criteria for moving DRAM from pilot to full-program status include:

On March 1, 2017, a DRAM Evaluation Plan workshop was held to discuss the goals, objectives, data sources, and key metrics for demonstrating the success of the DRAM. In D.16-09-056, the following above success criteria were adopted.

On April 1, 2017, the CPUC released a final DRAM Evaluation Plan & Metrics.

Evaluation Results

On July 26, 2018, a workshop was held on the DRAM pilots evaluation to discuss staff’s preliminary results against Metrics 1, 2, 3, and 5 and whether an additional one-year pilot for 2020 delivery should be approved. The CPUC’s Energy Division initiated the assessment effort last year and focused primarily on results from DRAM I and II (for contract deliveries in 2016 and 2017), although analysis of some issues did consider data from DRAM III procurement conducted in 2017 (for delivery in 2018 and 2019). The CPUC assessed the success of the DRAM pilots according to the following evaluation criteria:

1. Did the DRAM engage new, viable, third-party providers? Result: Mixed. The CPUC observed that preliminary results of the DRAM pilot evaluation were “mixed” when it comes to engaging new DR providers as 10 out of 15 DRAM I-III contract winners were “new participants” and most bidders were new to DR programs in California, but new bidder engagement declined in successive IOU auctions, leading to some concern about market concentration. 94% of total capacity across DRAM I-III were controlled by five DR providers. The CPUC also found that it was not clear how “viable” winning DR providers were as the pilots experienced contract terminations and reassignments, which led to some DR providers to exit DRAM. DR providers cited many implementation-related issues (e.g., CAISO integration, customer registration and data access) as challenges in participating in the DRAM, according to a survey of DR providers conducted by the CPUC staff in November 2017.

2. Did it engage new customers? Result: Yes. The DRAM was successful in engaging new customers (e.g., 95% of DRAM I participants were new to DR), including the participation of low-income and energy efficiency customers, though the CPUC identified that most customers were not high-energy users.

3. Were auction bid prices competitive? Result: Mostly yes. Auction bid prices were found to be mostly competitive, with SCE and PG&E DRAM I-III capacity prices less than the long-term avoided cost of generation for 2017-2019. For SDG&E, however, DRAM capacity prices were more than the long-term avoided cost of generation for 2017 and 2018 but less than that of 2016 and 2019, leading to mixed results.

4. Were offer prices competitive in the wholesale markets? Result: TBD.

5. Did DR providers aggregate their contracted capacity in a timely manner? Result: Mixed, but improving. The CPUC reported that the results were mixed but improving in DR providers aggregated contracted capacity in 60-day supply plans and demonstrated capacity. From DRAM I to II, for example, the percentage of demonstrated capacity increased from 58% to 88%, with higher levels of compliance from non-residential customers. A number of factors were identified as affecting contract compliance, including customer data access, overly optimistic customer acquisition projections, dual participation restrictions, and delays in receiving SGIP incentives.

6. Were resources reliable when dispatched? Result: TBD.

Due to data quality issues and “internal inconsistencies”, the CPUC found significant challenges in evaluating the CAISO-related criteria (Metric 4 and 6) and instead plans to contract with an external consultant to address data quality issues and internal inconsistencies. Generally, the CPUC also made helpful observations about energy storage resources in DRAM, where energy storage demonstrated the highest willingness to be dispatched, highest number of hours dispatched, and shorter dispatch notification requirements (i.e., greater participation in the real-time market). Informal comments were submitted by several parties. SCE and PG&E believed that additional information should be assessed and factored into the evaluation, including an additional survey to assess DRAM 2017 participants, along with a survey of the IOUs to get a “more balanced” analysis (as opposed to just the DR provider perspective). Given the CAISO integration challenges, the IOUs indicated that they hope DR providers will factor those costs into their bids. The IOUs expressed concern with the lack of performance guarantees, limited penalties, and limited enforcement of performance and capabilities of DRAM resources. Other parties recommended that the CPUC figure out ways to aggregate and anonymize certain data rather than to redact large portions of the report.

On October 25, 2018, a PD was issued that declined to authorize funding for additional auctions until the evaluation, which was targeted for completion in in December 2018, was completed and reviewed by the CPUC, especially since the additional auction pilot results will not contribute to the final evaluation. The PD unfortunately landed on several issues that were contrary to positions that CESA has advocated for. CESA recommended that the decision on whether to authorize an additional auction pilot should be delayed until a working group is convened to consider reforms to the DRAM with additional learning objectives. CESA worked with members and other DR providers to prepare next steps and consider workable sizes, terms, and other modifications to a potential 2020 DRAM.

See CESA’s comments on November 14, 2018 on the Proposed Decision

The CPUC’s Energy Division reviewed CESA’s comments and requested some informal ideas from CESA on potential solutions that could be incorporated into a new DRAM auction. CESA submitted informal feedback that proposed some concrete ideas for each of the perceived and real shortcomings of the DRAM as a viable (potential) permanent mechanism to procure third-party supply-side DR going forward. Most of all, we focused on addressing the IOUs' concerns about DRAM resource performance in aggregating into supply plans and in demonstrating their capacity. Though a long shot, CESA advocated for quick-turnaround processes to discuss DRAM improvements to test whether DRAM resources can perform with real RA obligations (e.g., deliver in supply plans, demonstrate capacity)

On December 10, 2018, D.18-11-029 was issued without any material changes from the PD. The decision determined that record development for critical improvements could not be completed in time for a spring 2019 auction and that third-party opportunities exist with utility DR programs. Instead, the decision directed the CPUC to develop a proposal for improvements to the DRAM based on the evaluation results in Q1 2019. In particular, the decision limited the value-stacking opportunities for BTM energy storage resources due to prohibitions around dual participation and have a key procurement vehicle removed for third-party DR resources via the DRAM. In response to comments to the PD, the decision explained that it could not provide detailed next steps until the evaluation is completed.

On December 6 and 12, 2018, SCE and PG&E filed motions, respectively, to submit an independent audit by Nexant in conjunction with the DRAM evaluation report. They noted their concerns with a DRAM seller claiming demonstrated capacity under the DRAM III contract that actually averaged three times overall customer usage. DR providers did not object to this audit report but cautioned that the CPUC not take a single seller’s actions as representative of other sellers and requested that any changes to the DRAM coming from these audits be done in a transparent manner.

On January 4, 2019, a Ruling was issued that presented the final DRAM evaluation results and recommendations and directed parties to file additional recommendations by January 11 to provide a general description of their recommendations. Overall, the DRAM pilots were found to be successful or mostly successful in the market transformation and solicitation related metrics, but there were mixed results related to the performance in aggregating contracted capacity and in bidding/dispatching into the market. Energy storage resources, in particular, appeared to fare well across many metrics. With this evaluation completed, the CPUC staff recommended the authorization of a new multi-year DRAM, depending on program design improvements. CESA offered the following recommendations:

• Formal comment opportunity is needed following the DRAM workshop on January 16, 2019 to develop the record on detailed proposals prior to the February 11-12, 2019.

• Formal comment opportunity is also needed following the DRAM workshop on January 16, 2019 to provide stakeholder input on the DRAM Evaluation Report.

• DRAM should be authorized for another 6 years, predicated on implementing the identified critical and necessary improvements in program design.

• A process for ongoing monitoring should be created, but any consideration of improvements or changes to program design should occur in a set timeframe.

• Rolling auctions should be conducted every year, starting at the 2019 budget and MW levels and up to a 2 GW cumulative total across the 6 year authorization.

• A market share cap for any single DRP within a single IOU territory should be established.

• A residential set-aside should be maintained.

• The RA proposal from the Supply-Side Working Group (SSWG) should be considered for the DRAM to address the issue of no CPUC-approved QC value.

• Penalties for non-performance when QC indicated on the supply plans falls significantly below contracted capacity may be reasonable, but it depends on the tolerance band.

• Any performance-based requirements should be assessed against the performance requirements of other non-DRAM RA resources.

• The Advice Letter approval process for executed contracts should be removed to support the streamlining of DRAM resource deployments.

• The DRAM should allow for the provision of any RA products (System, Local, and Flexible).

• Specific pro forma contract changes will depend on specific program improvements. Any changes in the program design should be translated to the pro forma contract.

See CESA’s informal comments on January 11, 2019 on the Ruling

On January 16, 2019, a workshop was held to present the DRAM evaluation results and recommendations. Participants had a fundamental discussion around the target activity and performance expectations for DR resources providing RA capacity, including whether there should be some minimum hours of dispatch and/or some level of active scheduling rates, especially when compared to other types of resources that are generally more active (e.g., LCR storage, supply-side utility DR resources). However, the counterpoint to this view is that the DRAM resources were likely operating appropriating as RA resources, which only require resources to be available according to their must-offer obligations, not that they bid in the day-ahead market at some “expected” level. So long as resources operate according to their RA requirements, CESA believes that DRAM resources still provide value even when being dispatched infrequently for the most distressed peak periods of the grid, though we will seek to ensure that solicitations and contracts attribute a higher value to resources, such as energy storage, that can be dispatched and utilized frequently with high levels of performance. Other improvement areas were discussed, but the broader focus of the workshop was on improving the performance aspects of DRAM resources under this 5-6 year extension.

Demand Response Auction Mechanism (DRAM) Step 1

Background

On January 23, 2019, a Ruling was issued that established two new working groups focused on developing recommendations for performance and accountability, and for changes to the pro forma contract. Working Group 1 would focus on proposed improvements for performance and accountability. Working Group 2 would focus on improvements to the DRAM pro forma contracts that will likely take recommendations from Working Group 1.

Step 1 Refinements

On February 11-12, 2019, workshops were held to discuss the goals and objectives for DRAM, proposals to ensure Qualifying Capacity and improve performance, proposals to ensure accuracy of demonstrated capacity invoicing, proposals for contract improvements, and whether the DRAM should have an energy component and higher dispatch hours. Workshop participants also discussed the option of the CPUC adopting a short-term plan and a long-term plan (i.e., “Two-Step Approach”). PG&E proposed this approach and explained that, in its proposed short-term plan, it envisions the CPUC would authorize a bridge period (2019 solicitation with 2020 deliveries) for the DRAM with critical improvements to the mechanism, while, in the long-term plan, parties would work together to resolve longer-term improvements. PG&E clarified that the Two-Step Approach would entail the CPUC approving the DRAM on a permanent but iterative basis, with improvements implemented on a regular basis. Several participants voiced support for the Two-Step Approach, but others contended that the evaluation results indicate the mechanism needs more than a few minor tweaks.

PG&E expressed concern that the CPUC has not adopted a goal or objectives for the DRAM. Based on small group discussions at the workshop, parties arrived at the following list of goals:

• Grow resources that meet grid needs while ensuring value to the customer

• Represent a percentage of RA procurement to cost-effectively provide for reliable carbon-reduction that also provides market certainty to third-party DR providers

• Cost-effectively (in terms of least-cost, best-fit procurement) displace flexible gas-fired resources by providing flexible resources to meet grid needs through a market-based, fungible, standardized product

• Use a cost-competitive mechanism to procure reliable DR to meet grid needs and grow DR

• Drive the growth of third-party standardized, fungible, reliable DR products that benefit the grid through the wholesale market where the benefits exceed the costs

• Enable third-party providers to compete to provide integrated grid services that meet grid needs where benefits are greater than costs

Parties also developed a list of objectives for the DRAM:

• Procurement Increase: Resources procured by the DRAM represent X percent of the ramp or X percent of total DR resources procured by 2025

• Customer Sustainability: The number of current customers increase by X percent annually

• Level Playing Field: Procurement of DR by utilities and by third-party providers are equal by 2025

• Customer Performance: Customer performance is 100% by 2025

• Customer Performance: Customers are 100% compliant with CAISO reliability criteria by 2025

• Customer Engagement: The number of new customers engaged increase by X percent annually

• Customer Performance: Monthly Demonstrated Capacity equals 90% by 2025

• Emissions Reduction: Emissions are reduced by X percent annually due to the auction mechanism resources

• Procurement Increase: Resources are procured at an increase of X percent annually

Finally, a set of principles were developed by workshop participants:

• The DRAM and its processes should be transparent

• Oversight should be consistent across all contracts

• There should be a level playing field for all third-party providers

• There should be a level playing field for third-party providers and utilities

On February 28, 2019, a Ruling was issued that recapped the workshop discussions and posed a list of questions on PG&E’s proposed Two-Step Approach and the merits of the various proposals for DRAM improvements as well as how to prioritize these proposals as either short-term or long-term activities. CESA recommended that the DRAM should be refined and improved in incremental ways but should not make drastic changes over a short timeframe without further discussion and should not burden all DRPs, including many high and honest performers, due to a few bad actors. CESA also expressed some concerns that the proposed reforms and improvements are too numerous and may overly complicate the DRAM and create unnecessary administrative burdens if the collection of ideas are not screened to determine the best few that would accomplish the goals of the DRAM. Finally, CESA provided our responses to the questions posed in the Ruling, structured under the following key recommendation points.

• The proposed two-step approach should be adopted with Step 1 focusing on minor improvements to ensure timely and successful implementation of the “bridge” 2019 auction and with Step 2 focusing on the appropriate long-term goals and improvements.

• Clear and broad goals, flexible but focused objectives, and the four principles identified at the workshop should be adopted.

• Multiple options for verifying qualifying capacity in supply plans and invoicing on demonstrated capacity should be allowed.

• Minimum dispatch hour performance requirements should be aligned with actual reliability and capacity needs.

• Penalties and incentives should mirror that of the Capacity Bidding Program (CBP).

• Limited contract changes should be made at this time.

• Market transformation remains an important objective of the DRAM and limited set-asides should be maintained to encourage new entrants and residential customer participation.

• Reporting and monitoring is prudent but should be balanced against administrative costs to the Commission, utilities, and demand response providers.

• The average August bid price cap should be replaced with the Net Market Value cap.

Many parties submitted comments in support of PG&E’s two-step approach, with SDG&E taking the strongest opposing view that the DRAM should be eliminated so that DR resources compete with other resources in a “non-siloed” basis. The IOUs and PAO were aligned in believing that substantive changes are needed to authorize a Step 1 auction and that the next DRAM process should not be accelerated, while industry supported minor changes to ensure a timely Step 1 auction and discussions on major improvements to occur in parallel. PG&E added that Step 1 must be structured to support an evaluation for the CPUC to determine whether to pursue Step 2. Regarding the Step 1 budget, DRPs generally supported a multi-year budget with a trajectory to 1 GW but the IOUs and CESA recommended a pilot level budget in line with the 2019 DRAM auction. CESA reinforced our opening comments in response to other parties by making the following points:

• Until a pervasive problem is identified around the ability to deliver contracted capacity into the utilities’ Supply Plans, additional testing for Qualifying Capacity should not be adopted at this time.

• Penalties and incentives should mirror the CBP in the short term as other long-term structural changes are explored at a later time.

• Reasonably-sized set-asides should continue to promote necessary market transformation while fostering competitive and reliable outcomes for the majority of megawatts available in the DRAM.

• Minimum dispatch hours and energy components should be explored later.

See CESA’s comments and reply comments submitted on March 29, 2019 and April 10, 2019 on the DRAM Improvements Workshop Ruling

On May 31, 2019, a PD was issued on May 31 that proposed a four-year continuation of the DRAM due to positive results related to the market transformation metrics (e.g., new DRPs, new customers) but would require improvements to address shortcomings in performance, reliability, and competitive price offers. CESA commented on the PD on how the DRAM is ready to move beyond the ‘pilot concept’ into a ‘mainstream’ procurement mechanism for third-party DR resources. CESA also offered the following recommendations regarding the DRAM:

• The CPUC should approve the four-year continuation of the DRAM with larger budgets in Step 2, but if not, minimally authorize annual budgets of $27 million across the three IOUs for 2019 to 2022.

• The contract capacity should be used for year-ahead QC and may need to be used for resources with insufficient historical data.

• The “new market entrant” definition is too restrictive and should be modified to allow for entities with some “low” level of DR activity in California to qualify.

• Performance reporting should be done quarterly to better manage the administrative burden.

See CESA’s comments on June 20, 2019 on the Proposed Decision

Views on the PD ranged from support as a reasonable balance but with some modifications and clarifications needed (DRPs, PAO, PG&E, SCE), support with some “re-balancing” needed to make the full four-year extension contingent on early outcomes (Olivine, CLECA), and oppose pilot extension altogether (SDG&E). The DRPs made many similar points as CESA around the inappropriate budget reduction and 2019 budget proration, problematic use of historical data for year-ahead QC, defining “new market entrant” more flexibly, and challenge of monthly performance reporting. Some of the key themes included the following:

• PG&E advocated for penalties or de-rates for significant shortfalls in QC values and differentiation of QC by month and weather while PAO expressed concerns about ratepayers having to pay the shortfalls between year-ahead and month-ahead QC in the form of RA replacement costs.

• PAO and PG&E recommended at least one dispatch or test within the first two months of the contract year to avoid extended time of unsubstantiated capacity and PG&E provided recommendations for concurrent testing to be done at the sub-LAP level for at least two consecutive hours similar to other RA resources. DRPs, however, argued that no other market requires such frequent dispatch or testing requirements.

• PG&E, SCE, and PAO recommended proration across the full range of DC performance to avoid incentives to perform at lower levels for equivalent payments.

• PG&E and SCE highlighted a potential gap in the default provisions where a DRP could alternate between a test/dispatch and must-offer obligation (MOO) option each month to avoid default despite less than 50% DC in test or dispatch.

• DRPs expressed that it is preferable to use timely and accurate full invoices as opposed to a partial invoice to settle payments since lost revenues can be harmful to customers and DRPs.

• CLECA and SCE contended that the DRAM should be subject to a cost-effectiveness requirement and have transparency into how much revenue is passed through to the customer. This is concerning because cost-effectiveness tests do not seem appropriate for a procurement mechanism (i.e., this is not an administrative DR program) where bid caps and competitive bid evaluation criteria are used. Furthermore, DRAM resources are supply-side resources where understanding of direct customer benefits in the form of revenue pass-through is unnecessary and represents proprietary information

• CAISO and CLECA agreed on the exclusion of RDRR from the DRAM. The DRPs disagreed because this exclusion would direct RDRR DRAM customers into utility DR programs and more record development is needed to define “frequently enough”.

• CLECA, Olivine, SCE, and SDG&E griped with the incorrect record on how the DRAM Evaluation Report reported on the evaluation criteria around competitive auction bid prices, new DRP engagement, etc.

On July 12, 2019, D.19-07-009 was issued that proposed a four-year continuation of the DRAM due to positive results related to the market transformation metrics (e.g., new DRPs, new customers) but would require improvements to address shortcomings in performance, reliability, and competitive price offers. A 2019 solicitation is authorized for a pro-rated $12.78-million budget (7 months of delivery) while annual solicitations from 2020 to 2022 are authorized with annual $14-million budgets ($6 million each for PG&E and SCE, $2 million for SDG&E). For the 2019 solicitation for 2020 deliveries, the following schedule was established:

Over the next four years, a hybrid two-step approach through 2022 is adopted that ensures the most critical inadequacies are addressed for a 2019 solicitation, continues to improve the more challenging processes to ensure reliability and performance, and preserves the successful efforts of the past four years while minimizing program disruption. With the extension through 2022, the determination on the permanency of the DRAM will be made at the same time the next five-year DR application is expected to be submitted in November 2021. An independent evaluator and an evaluation program will be set up to inform the review of the 2019-2022 DRAM continuations, with a final evaluation report available to parties by December 1, 2021. Solicitations for 2020 through 2022 will likely occur in Q1 of each year. Importantly, several improvements and changes for Step 1 were made, including the following for the 2019 solicitation:

• Qualifying capacity (QC) estimates: Accurate QC estimates shall be provided three times: at submission of a bid into the auction, in the year-ahead RA filing, and in the monthly supply plan, and shall be estimated by referencing historical performance data (past test events, past market dispatches, or suitable publicly available performance data with similar characteristics). Historical reference data will be based on customer class, nature of load being aggregated, dispatch method, number of service accounts, aggregated load, and percentage of load impact or reduction. For storage, the DR capacity will be based on projected aggregated capacity. DR performance assessment will be estimated using 1-in-2 weather condition guidelines noted in D.14-06-055. QC estimates and supporting data must be submitted at least 10 business days ahead of month-ahead and year-ahead filings to allow IOUs time for review and analysis of new QC data submissions.

• Demonstrated capacity (DC) invoices: Penalties shall be imposed for DC shortfalls for a delivery month relative to the QC on the monthly RA Supply Plan, with the IOUs being permitted to default a DRP contract if aggregate DC falls below 50% for two months in a row, after excluding any intervening months with invoices based on MOO option. Invoices for DC shall be calculated as average performance at the resource level and be based on a capacity test or market dispatch during 50% of the contracted months, one of which must be a full resource dispatch for at least two consecutive hours in August, with the number of consecutive months allowed with no dispatches limited to 5 months. A combination of a market dispatch and a test may satisfy the two consecutive hour requirement if the CAISO market dispatch does not cover the two consecutive hours. Invoices for DC shall be due 30 days after the Seller has received 95% of RQMD for a resource’s dispatch event intervals for a showing month; a partial invoice with available data may be submitted within 30 days if the Seller does not receive 95% of RQMD.

• Solicitation: The August bid price cap is eliminated but an alternate is not adopted at this time as the long-term avoided cost of generation criteria still applies. The 20% residential set-aside is replaced with a 10% set-aside for new market entrants, defined as a DRP who has not integrated any DR resources into the CAISO market (e.g., DRAM, RA contracts) during the three years prior to a new DRAM solicitation. RDRRs are excluded from the DRAM for Step 1 due to the lack of regular use to address grid reliability needs.

• Reporting: The IOUs are required to publish DRAM contract summaries to improve transparency (i.e., counterparties, product type, customer class, contracted capacity by August MW volume, contract term). All DRAM resources are required to submit quarterly performance reporting to the CPUC within 30 to 60 days after the end of the showing month.

• Other: Service account movements are prohibited except when newly enrolled customers are added to a resource, a customer exits the DRAM, a customer must be moved to meet CAISO telemetry or market participation threshold requirements, or a customer changes LSEs if the CAISO has not removed the single LSE requirement.

With an improved method for estimating QC based on historical load data, the penalties for DC shortfalls mirror the structure of the CBP, as shown below. Additionally, over-performance incentives were not adopted, with the decision referencing the CAISO’s concern about the costs of system re-dispatch if resources do not perform according to their dispatch instructions.

For Step 2, a working group is directed meet starting on July 15, 2019 to address the following remaining issues in time for a final report by August 9, 2019 and a second decision no later than December 2019:

• Replacement for August bid price

• Minimum dispatch hours

• RQMD penalty and contract remedy

• Contract partitioning and reassignment

• Bid fees

• CAISO registrations and meter reprogramming for extension

• Guidelines for IOU audits and withholding invoice payments

• Data authorization, collection, and protections

As compared to the PD, the decision made several key changes or clarifications, such as the following:

• Increase the 2019 pro-rated budget from $8.2M (PD) to $12.78M (D.19-07-009) based on seven-month capacity reflecting from June to December, similar to the Capacity Bidding Program (CBP), thereby setting budgets at $5.7M for PG&E, $5.16M for SCE, and $1.92M for SDG&E.

• Maintaining the $14M/year combined budget across all three IOUs for DRAM auctions from 2020-2022 due to the two-auction budget in 2018 approved by D.17-10-017 being a “special case”.

• Waiving RA penalties for 2019 solicitations for 2020 deliveries (as recommended by PG&E) to allow the IOUs to gain experience in verifying QC.

• Requiring quarterly performance reports (instead of monthly reports) due to same benefit but reduced burden of such requirements.

• Changing the definition of new market entrant to focus on providers who have not participated in a market-integrated DR program during the past three years (e.g., DRAM, RA contract) to provide additional flexibility to attract new providers, which differentiates the challenges of supply-side and load-modifying-only DR resources.

• Changing the dispatch requirement to align with the RA requirement (i.e., full resource dispatch for at least two consecutive hours).

• Modifying the tolerance band for performance between 50% to 70% of QC to establish pro-rated penalties as a percentage of DC delivered (instead of QC) with a de-rate factor of 75% (instead of 50%) to ensure performance and deter unwanted market behavior.

• Modifying DC invoice requirements to be based on either market dispatches or capacity test events in 50% of the contracted months (instead of 6 out of 12 months) to address gaps where a DRAM resource may not be contracted for 12 months.

• Modifying terms to permit defaulting of contract if DC is 50% or less than QC for two sequential months after excluding intervening months with invoices based on must-offer obligation (MOO), which addresses a gap in DRPs using the MOO every other month to avoid default.

• Allowing for only System and Flexible RA to be procured in 2019 solicitation due to 100% Local RA showing in year-ahead filing, but all three RA products may be procured in post-2019 solicitations.

• Clarifying that the aggregation of concurrently dispatched resource IDs for Local RA is only allowed for resources within the same SubLAP.

• Maintaining that MGO baseline issues will be considered in the next DR applications (2023-2028).

Overall, the final decision was an improvement over the PD in appropriately increasing the pro-rated 2019 budget, moving toward less onerous performance reporting requirements, opening up opportunities for RA opportunities beyond just System RA, and adopting a more flexible “new market entrant” definition, in line with comments from CESA and the DRPs. Otherwise, many of the changes were related to reasonable changes offered by the IOUs to close any gaps in performance, QC estimation, and DC invoicing. The decision was still problematic for maintaining the small pilot-sized annual budgets for 2020-2022, which will limit opportunities for members.

Demand Response Auction Mechanism (DRAM) Step 2

Background

On January 23, 2019, a Ruling was issued that established two new working groups focused on developing recommendations for performance and accountability, and for changes to the pro forma contract. Working Group 1 would focus on proposed improvements for performance and accountability. Working Group 2 would focus on improvements to the DRAM pro forma contracts that will likely take recommendations from Working Group 1.

Step 2 Refinements

On August 9, 2019, a working group was published following workshop discussions held from July to August 2019 to discuss a number of outstanding items that were not settled, including the below items, but the CPUC clarified that the permanence of the DRAM will be decided at the end of the 2018-2022 DR Application proceeding:

• Replacement for August bid price

• Minimum dispatch hours

• RQMD penalty and contract remedy

• Contract partitioning and reassignment

• Bid fees

• CAISO registrations and meter reprogramming for extension

• Guidelines for IOU audits and withholding invoice payments

• Data authorization, collection, and protections

First, on minimum dispatch hours, the CPUC expressed its intent to make DRAM resources more active in the CAISO market and the CAISO expressed that it is looking to figure out a way for resources to bid economically, not at the bid cap. The CAISO pointed to data showing that the day-ahead locational marginal price almost always cleared above the net benefits test (NBT) during the availability assessment hours in July and August 2018, showing that opportunities existed for PDR resources to submit competitive bids in the CAISO market. The CPUC also produced data analysis of how net load peak conditions roughly correlated with day-ahead market prices, though the correlation was not as strong as expected (R = 0.46). 

While the IOUs are required to bid economically, third-party DRPs cannot be mandated by the CPUC to bid economically, leading the CPUC staff to propose a ‘floor’ for dispatch activity as a proxy for economic bidding. The DRPs observed that minimum dispatch hours could be established for high-demand hours.

CEDMC opposed a minimum dispatch requirement since dispatch decisions are dependent on market conditions and the opportunity cost of the DRAM resource and would represent a significant change to the RA Program. CEDMC added that there is already a minimum dispatch requirement within the DRAM – i.e., six dispatches or tests over a 12-month period. Finally, CEDMC opposed voluntary bid parameters because of the dynamic nature of opportunity costs. PG&E agreed and opposed purchasing energy from DRAM because no other RA product requires a minimum energy dispatch requirement and since it would be administratively difficult to enforce. Instead, PG&E recommended that third parties be required to provide information on their bidding characteristics akin to the IOU’s least-cost dispatch reporting metrics and to explain when dispatch did not occur when the market clearing price is below their marginal cost.  

Second, the working group discussed whether cost-effectiveness protocols should be applied to and potential cost-benefit analysis should be included in the DRAM. Given that the budget allocation is arbitrarily set rather than based on need, the CPUC and CLECA advocated for the inclusion of cost-effectiveness measurements, which raised what costs to include, such as the cost of the contract and overhead (e.g., IT, administration). CEDMC opposed using a cost-effectiveness methodology for DRAM since no mandate was given in D.19-07-009. CEDMC added that DRAM is a procurement mechanism, not a DR program. However, PG&E and SCE explained that DRAM does not fit well with the LCBF cost-effectiveness methodology, as DRAM is a short-term contract that is for capacity only and is not tied to need – i.e., if there is a lack of RA need, all of the bids have a negative NMV. Instead, PG&E and SCE advocated for aligning the IRP and RA proceedings and pointed to Resolution E-4728 (p. 24) on how a cost-effectiveness benchmark calculation should be conducted to compare the relative value of DRAM versus other types of capacity. If DRAM is not treated as a DR program, they proposed that LCBF evaluation guidelines be used where bidders would provide information about the A-G (but not D) factors associated with the parameters under which their DRAM resources will operate in order to support the qualitative evaluation of bids.

Third, on RQMD penalties andcontract remedies, the working group discussed how the IOUs not providing timely RQMD data can inhibit DRPs from settling with the CAISO, calculate or estimate resource performance, and enroll customers in CAISO resources. In these situations, PG&E commented that remedy solutions are already in place in the DRAM contract. Meanwhile, OhmConnect proposed a service level agreement (SLA) to ensure some standard of data delivery. Other potential vehicles for remedies include pro forma contract breach language, Rule 24/32 tariff changes, financial penalties per infraction, upfront fees to reimburse DRPs for CAISO penalties incurred, and/or CPUC dispute resolution process. PG&E, however, worried that such fees could create perverse incentives for the DRPs to not communicate to the IOU about the data problem in order to receive the penalty payment later and explained that data delivery issues can sometimes be outside of the IOU’s control. PG&E also commented that the proposed SLA is one-sided and that DRPs should troubleshoot issues to some extent on their side as well. With performance metrics being developed on the click-through and data delivery process, PG&E believed an SLA is premature. Overall, PG&E indicated that the Rule 24 and DRAM contract provisions in place are sufficient and new remedies are not required.

Fourth, on contract reassignment and partitioning, the CPUC wanted the working group to explore whether a process could be established to create a pathway for the defaulting seller and more efficiently allocate capacity to DRPs that can deliver on the contract while not being unduly burdensome to the IOUs to implement. OhmConnect proposed that DRPs identify the MW capacity that it wishes to partition, inform the buyer of the partitioned capacity, and then select the willing counterparty to take the reassigned capacity. A modified contract would be delivered and executed between the DRP, counterparty, and buyer. If partitioning is allowed, OhmConnect expressed that this must be completed in advance of the supply plan deadline and the contract price must be the same or lower than the original contract price. Additional potential restrictions could include prohibiting near-default DRPs, ineligible DRPs, or previously partitioned and reassigned contracts from partitioning or reassigning contracts. However, SCE expressed that reassignments and partitions create gaming risks and may result in increased market concentration, additional overstatement or inaccuracy of assigned capacity (e.g., double counting, inaccurate assessment of customer load, interference with supply plans), and overbidding into RFOs to secure more capacity than can actually be delivered.

Finally, the working group addressed a number of other items:

• Other than SDG&E, no other party pushed for bid fees to be included in the DRAM. CEDMC proposed establishing milestones as opposed to bid fees to not discriminate against new entrants and to simplify implementation while creating more rigorous requirements. Furthermore, CEDMC proposed to establish pre-conditions to bid into solicitations and to give bid winners up to three days to accept the award.

• In place of the August bid cap, which was removed in the decision, SDG&E proposed that the short-run avoided cost (SRAC) of generation be used as the price cap for the bid selection process to account for how RA values vary by month. The CPUC clarified that the long-run avoided cost (LRAC) approach will be used for the 2019 solicitation until a different proposal could be adopted. The DRPs did not support SDG&E’s proposal and instead favored an NPV methodology without finding a replacement for the August bid price cap.

• The IOUs circulated edits to the DRAM pro forma contract pursuant to the decision and discussed them at the July 23-24 meetings. However, a major issue for validating QC was highlighted by the DRPs, where much of the information about nature of aggregated load, dispatch method, projected aggregated load, and projected percentage of load impact or reduction may not be available at bid submission or in the year-ahead submission. The DRPs also found the methodology to sub-divide contracts with heterogenous combination of resource types to apply a weighted average to estimate QC, which can be onerous and involve market-sensitive customer-specific data. CESA also had concerns with the use of publicly-available performance data where historical data is not available, but it is unclear if such reference data exists.

• PG&E submitted a proposal to determine whether additional funding for meter reprogramming and CAISO registrations is appropriate, with the DRPs potentially paying for this expense. For each customer that participates with a DR provider, the IOUs must create an individual customer registration so that the customer’s activity in CAISO systems as well as their usage data can be tracked and processed – an expense that was previously covered in Rule 24 budgets. Additional funding may be needed to increase Rule 24 registration limits.

• Due to the extensive data submission requirements pursuant to D.19-07-009, JDRPs proposed that utility audits should be limited to requesting information necessary to validate the invoices, which should be done to an independent monitor subject to an NDA as opposed to being submitted to the utilities.

• OhmConnect proposed a dispute resolution process for when the IOUs do not have sufficient confidence in the capacity listed in month-ahead supply plans, whereby an independent monitor receives all data from DRPs 10 business days ahead of a filing and makes a recommendation to the IOUs on whether to derate the capacity, though the IOU has sole discretion to make the final decision. If the demonstrated capacity turns out to be greater than the derated capacity via dispatch or test, the DRPs would then be paid accordingly. To disincentivize derates in every month, OhmConnect recommended that two or more instances of demonstration above the forced derate would eliminate the remaining testing requirements for the DRPs. As for disputes related to demonstrated capacity, OhmConnect recommended an informal dispute resolution process that bounds the timelines for resolution of the dispute.

CESA responded to questions posed in Appendix C of D.19-07-009 and cautioned the CPUC about adopting too many substantive changes at once, especially as the ‘Step 1’ changes from D.19-07-009 have yet to take effect and could turn out to address some or many of the concerns expressed in the DRAM Evaluation Report.  At the same time, CESA supported the continued discussion on several Step 2 improvements, including around how the CPUC and IOUs can extract and be assured of greater value from DRAM resources by being dispatched more frequently for energy while not discriminating against DRAM resources as RA capacity-only resources. Specifically, CESA made the following high-level recommendations:

• Instead of minimum dispatch hours, DRAM participants should be required to submit bid data to the Commission for a reasonableness assessment.

• Voluntary bid parameters should be further explored to assess expected energy in the auction bid selection process.

• Cost-effectiveness should continue to be assessed on an ex ante basis in the solicitation bid evaluation stage.

• Contract reassignment and partitioning should be allowed with disincentives for ‘gaming’ through qualitative bid evaluation criteria.

See CESA’s comments on August 23, 2019 on Appendix C questions of D.19-07-009 and working group report

On November 15, 2019, a PD was issued that made determinations around the “Step 2” refinements to the DRAM, which, among other things, affirmed that DRAM is a mechanism to procure capacity and energy consistent with D.19-10-021 and established a process to measure the cost effectiveness of DRAM resources. CESA recommended that energy requirements should not be adopted at this time in order to assess the results and outcomes of Step 1 refinements while further discussing alternative approaches. Energy requirements could lead to unintended impacts where DRAM resources may be forced to uneconomically dispatch to meet this requirement. Furthermore, CESA commented that cost-effectiveness assessments should use least-cost best-fit evaluation guidelines without the factor parameters and that qualitative bid evaluation criteria should advance key objectives of the DRAM but should eliminate the criterion related to automated demand response.

See CESA’s comments on December 5, 2019 on the Proposed Decision

On December 23, 2019, D.19-12-040 was issued that approved the refinements and made revisions that: (1) affirmed that DRAM is a mechanism to procure both RA and energy; (2) modified the minimum energy requirement from just May-October to be delivered throughout the life of the contract, per CESA’s and others’ recommendation; (3) set the minimum energy requirement at the contract, not resource, level as being operationally easiest; (4) revised the average QC calculation to the three highest QC months on the month-ahead supply plan; and (5) removed the qualitative criteria around enabling automated dispatch due to the inability to verify this in bidding, among other modifications to weighting and thresholds. Other changes involved the scope of the follow-up DRAM Working Group.

Regarding the biggest change to add a minimum energy requirement, the decision cited the CBP with specific trigger prices and all-source LCR solicitations with locked-in marginal cost of energy dispatch where DR resources are subject to energy market participation, as well as the recent RA imports decision. The decision also underscored how the DRAM is a carve-out, not a traditional procurement mechanism, thereby supporting the CPUC’s decision to add stricter requirements. Specifically, the decision determined that, starting with the 2021 auction, DRAM resources must deliver at least 30 MWh per MW of average QC in the monthly supply plans for the contracted months, which provides flexibility to providers to competitively bid and dispatch resources when market prices are above marginal costs. For example, if the 3-month average QC of a resource is 5 MW, then 150 MWh is the minimum energy required (required energy quantity) to be delivered to the CAISO market by that resource through the Seller competitively bidding and dispatching, when scheduled, the resource into the energy market. The required energy quantity shall be delivered during the contracted months, with providers submitting documentation to the utility for invoicing as well as reporting on marginal costs on a quarterly basis for study purposes. The decision opted for a minimum energy requirement as opposed to a minimum dispatch hours requirement because of the issue of partial dispatches.

If the energy delivery requirement for the contracted months is not met, Sellers will be assessed a penalty based on the following calculation, applicable at the resource level: $10,000/MW x Average QC x (1 – delivered energy quantity/required energy quantity). The maximum penalty is set at $10,000 per MW based on an estimation of the 30 highest prices observed in the CAISO in 2017 and 2018. The above calculation allows for proration of the penalty.

Additionally, the decision determined that the use of least-cost, best-fit evaluation guidelines along with parameters based on factors used in DR cost-effectiveness protocols as best ensuring cost effectiveness while providing a level playing field, even as the mechanism is exempt from the cost-effectiveness requirement due to it being in the pilot phase, though the CPUC is encouraged to explore methodologies ahead of the 2022 DRAM auction. Given that the DRAM is not a traditional procurement mechanism, the factors will be used for informational purposes instead of short-term RA value or with alignment with the IRP, which is still in the early stages.

Finally, the decision approved the procurement of System, Local, and Flex RA beginning with the 2021 auction, finding significant value in optimizing for the right capacity products. There were a number of other refinements adopted, as shown below:

• Qualitative data: The decision adopted five qualitative criteria and cost adjustments (as indicated in parentheses, with cost reductions representing factors that increase competitiveness of offers) for bids submitted in auctions: (1) bidder is a certified small business (1% reduction); (2) previous shortlist offer declines (3%); (3) willful termination or default of contract (10% increase); (4) bidder delivered supply plans totaling less than 75% of contracted capacity (5% increase); and (5) bidder delivered demonstrated capacity invoices totaling more than 95% of its contracted capacity (5% reduction).

• No replacement for the August bid cap price: There are protections in place (e.g., ability to eliminate outliers) to avoid accepting bids that are not competitive in comparison to the rest of the offers.

• RQMD penalty and contract remedy: There is insufficient information regarding the frequency, cause, and consequences of RQMD delays to set penalties at this time, but investigations should continue.

• Contract reassignments: To improve transparency, the decision required providers seeking to reassign a contract to publicly notify all registered providers of the available megawatts for reassignment. Seller then selects a willing counterparty and provides the buyer with modified contracts. Upon review of documentation, all involved parties execute the contracts and the utility seeks CPUC Energy Division approval via a Tier 1 advice letter. Sub-contracting is allowed, but not contract partitioning.

• Bid fees: Milestones are adopted instead of bid fees since the latter could create new market entrant barriers and be more administratively burdensome.

• CAISO registrations and meter reprogramming: Given the unfairness of charging customers for reprogramming, the decision authorized an additional $600,000 for SDG&E to support meter reprogramming and provided an option for PG&E and SCE to submit a Tier 3 advice letter to request shifting of DR funds to support additional reprogramming and/or CAISO registrations if PG&E’s projections are exceeded, or SCE’s Click Through Application is denied.

• Utility audit guidelines: The decision clarified that the IOUs should have identical informal dispute resolution language regarding demonstrated capacity, provide advanced notice and communication if additional information is needed, require firewalls with appropriate utility staff conducting audits, and set a process for notifying providers and CPUC of audits.

• Dispute resolution process: The decision adopted two processes for disputes regarding qualifying capacity estimates: (1) parties agree on a de-rate of capacity in the month-ahead supply plan; or (2), if no agreement can be reached, the QC estimate stands but the seller must perform a test or dispatch. This process will be formalized in the pro forma contract. Several communication protocols were also adopted to resolve data issues, as well as provider milestones for CAISO registration, utility data systems integration, and CPUC registration (45 days prior to first supply plan submissions).

• Data confidentiality and reporting: The decision affirmed the firewall requirements for DRAM resource data and the need for data reporting to inform policymaking around the permanence of DRAM, thus denying requests to only request data from bad actors or performers. However, the PD adopted the principle that bid submittals represent the best estimate of the seller, with month-ahead data likely to be more detailed than year-ahead data.

The CPUC Energy Division will establish the workshop schedule ahead of the IOUs being required to file a Tier 2 advice letter on the refinements no later than January 31, 2020, for the 2021 auction that will launch by April 1, 2020, and September 15, 2021 and 2022 for the 2022 and 2023 auctions that will take place in February 2021 and 2022.

On February 18, 2020, a working group meeting was held to discuss annual refinements, focusing particularly on the LRAC. Considering the challenge of comparing LRAC to offers for a seven-month period in 2020, the independent evaluator (IE) of the 2020 DRAM RFOs highlighted challenges in assessing offers. Another key issue highlighted in the IE reports was the lack of awareness by bidders on how QC assessments would be incorporated in the bid evaluation process. Specifically, CEDMC recommended a methodology to compare DRAM bids to the LRAC that weighs each monthly portion of the LRAC with a RA value or a similar weighting proxy to compare against the LRAC. Considering IOUs' RA values are proprietary, CEDMC recommended a public proxy to weight each month of the year as a portion of the LRAC (e.g., SCE's Day-Ahead CBP tariff values). By contrast, since the DRAM is not tied to a specific need and is instead set to maximize a CPUC-approved budget, the IOUs argued that the LRAC functions as a fixed price cap to protect ratepayers from high, outlier bids. To avoid a “matching units” problem (i.e., LRAC in $/kW-year for 12-month terms versus offer prices in $/kW-“offer” for shorter than 12-month terms) and keep a simple methodology, the IOUs opposed partial-year bids. Alternatively, the IOUs offered to weight the LRAC by the SRAC to compare to the offer prices in only the months offered, but they wanted to affirm that this should not be precedent setting.

On June 23, 2020, a workshop was held on June 23 to further discuss the selected technical issues for the DRAM. Notably, the CAISO requested that the CPUC define the program parameters for third-party DR participating in DRAM and provide explicit guidance on the availability of DRAM resources. Without express CPUC guidance, the CAISO explained that DRAM resources have a 24x7 MOO pursuant to the CAISO tariff. Meanwhile, PG&E made a number of recommendations to refine the DRAM contract language, particularly due to inconsistencies between QC estimate methods using percentage of aggregated load versus per-service account load reduction.

Demand Response (DR) Baselines

Background

Baselines are used to measure and evaluate performance during dispatch events. The FERC electric tariff has approved for the Capacity Bidding Program (CBP) (wholesale settlements) the use of the 10-in-10 aggregate baseline with a +/- 20% day of adjustment cap for non-residential customers. However, the IOUs retail CBP program tariffs use the 10-in-10 individual baseline with a +-40% day of adjustment cap for non-residential customers. 

Wholesale-Retail Baselines

On March 22, 2019, a workshop was held where the IOUs presented on the similarities, differences, and interactions of wholesale (10-in-10 with day-of adjustment +/- 20%) and retail (10-in-10 with day-of adjustment +/- 40%) baselines. The IOUs cautioned against the use of CAISO wholesale baselines for the CBP since wholesale baselines are calculated at the aggregate level and does not measure the individual customer performance for the retail DR program for both capacity and energy measurement. The IOUs also underscored that the DRPs and Scheduling Coordinators (SCs) are now responsible for performing baseline calculations since adoption of the proposals from ESDER Phase 2 and that the complexity and costs for IT system work and settlement calculations would be significant compared to the benefits to implement into its retail DR programs. OhmConnect added that a combined methodology could be applied where the 10-in-10 baseline is used for all non-residential locations and the 5-in-10 baseline is used for all residential locations for resources that comprise a mix of non-residential and residential customers.

On April 8, 2019, A Ruling was issued on April 8 that raised some post-workshop follow-up questions, including on whether to address the Meter Generator Output (MGO) framework in this proceeding. PG&E and SCE recommended that the MGO policy issue be addressed in a future proceeding on new DR models because of several unaddressed questions around the entity that is responsible for quality and verification of data, synchronization of the MGO data with other data, how data will be used for settlement purposes, and dual participation rules that could be adopted. The use of the MGO in their view requires more analysis since it would allow sub-metered devices to register and settle for DR services as opposed to that being done at the premise (facility) level. This issue could not be properly resolved in time for a July 2019 decision.

The IOUs commented that no other retail baseline options (other than the 10-in-10 methodology) should be used in DRAM to settle capacity payments since the CPUC has yet to adopt them and that there are issues with the accuracy of incentive payments including RA for DRAM contracts. Generally, the IOUs believed an incremental approach should be used to roll out additional baselines, such as PG&E’s suggestion to expand to a day-matching 5-in-10 baseline to better support residential participants. PG&E raised the additional issue of using one option for energy (CAISO jurisdiction) and another option for the capacity baseline (CPUC jurisdiction), such as in the CBP, which should be made consistent to measure and settle performance. SCE added that it has no preference for which approved baseline is used to settle with the CAISO but it requested that the CPUC make this affirmation. Regarding DRAM, SCE and CEDMC argued that no CPUC approval is necessary since the DRAM purchase agreement already allows for the use of all CAISO baseline options, which ensure more accurate measurement of DRP aggregator performance, but CEDMC argued that the use of the current 10-in-10 baseline in the CBP is inaccurate for customers with inconsistent loads by day.

On July 12, 2019, D.19-07-009 was issued that approved four baseline methods recently approved by FERC for settlement purposes at the CAISO and in DC invoicing in the DRAM, which was determined to be both a wholesale and retail mechanism:

• Day-matching customer load 10-in-10 baseline with a 20% cap

• Weather-matching baseline with a 40% cap

• Use of control groups

• 5-in-10 baseline

However, the decision declined to adopt the MGO method since this is not the appropriate proceeding to address this issue, as certain issues would not apply solely to the current DR models. The decision also directed the IOUs to include a proposal for the costs of a 5-in-10 baseline for the CBP, especially for the residential option, which more effectively measures customer performance for those with variable or weather-sensitive loads. Implementation will be delayed, however, to the mid-cycle review in 2021 due to uncertain costs and benefits. A working group was established to address ongoing baseline issues for the 2023-2028 DR Applications:

• Assess if adjustment cap of +/– 40% is still suitable for retail 10-in-10 when the day-of adjustment for wholesale is +/– 20%.

• Consider whether the customer or the IOU/aggregator should select the retail baseline and determine the pros and cons of each.

• Consider flexibility in changing retail baselines.

• Consider whether the wholesale and retail baseline should be aligned, or if they can be different.

• Consider the pros and cons of an aggregate versus individual baseline.

The working group will begin to meet within 90 days after the issuance of this decision. A final report is required by April 1, 2021 to support IOU testimony for their 2023-2027 DR application to be field in November 2021. In response to a May 31, 2019 PD, CESA recommended that the PD be revised to allow for the use of the MGO baseline. The final decision recognized CESA’s comments but affirmed that MGO baseline issues will be dealt with in a future proceeding.

See CESA’s comments on June 20, 2019 on the Proposed Decision

On November 13, 2019, AEG, the selected consultant to the study effort, discussed its planned methodology:

• Create a weighted weather profile using all weather stations in each IOU (weighted according to customer distribution)

• Find top matches for event-like days

• Check weather distribution of event days versus event-like days at the IOU service territory level

• Check weather distribution of event days versus event-like days at the sub-LAP level

For the most part, AEG explained that temperatures rise and fall together through the region, just not in the same magnitudes. As a result, the top matches at the sub-LAP level will generally be the same days. If any sub-LAPs standout as having particularly bad matches, AEG will redo the match for these sub-LAPs. Participants expressed that AEG should be careful to use CBP hours in the MAPE/MPE calculations.

A final working group report is expected to be filed by the IOUs in November 2021 in testimony for their 2023-2027 DR Application.

Dual Demand Response (DR) Participation Policy

Background

On August 24, 2009, D.09-08-027 was issued that approved DR budgets for 2009-2011 but also established the first set of rules around dual participation. First, the decision made a distinction between capacity and energy programs, where capacity programs were defined as those that compensate a customer's willingness to curtail load when requested and energy programs were defined as those that compensate customers by the amount by which said customer reduced its peak consumption at a given time. Critical Peak Pricing (CPP) in particular was established as an energy program. Then, if a customers signed up for an energy and a capacity program and both are triggered during the same time period, the compensation will only come from the capacity program. Baselines for both energy and capacity programs would be calculated based on days in which no events are called in either program. The IOUs were directed to come up with specific rules governing dual participation. 

The IOUs generally held the view that dual participation presents reliability risks by complicating load drop forecasts (i.e., inaccurate forecasts to the CAISO) and presents double payment risks for a single load drop by allowing for customers to participate in two capacity programs or two energy programs. Gaming concerns, customer confusion, and administrative complexity were also raised as concerns. SDG&E allowed its customers to participate in multiple DR programs but limited the possible combination of programs to minimize conflict in triggers and establish a program hierarchy of payments. Third-party DR providers, however, sought equal treatment for third-party and utility DR customers in dual participation. 

On June 3, 2010, D.10-06-002 was issued that directed the IOUs to prepare to bid DR from existing Participating Load Pilot (PLP) programs into the CAISO's market as soon as feasible if FERC approves tariff language pursuant to Order 719 and Order 719-A. The initial conditions under which the CPUC will oversee retail direct DR bidding participation were approved. Importantly, this decision defined Proxy Demand Resource (PDR) as a product that allows DR providers to aggregate the DR of retail end-use customers to be bid into the CAISO's markets through a Scheduling Coordinator (SC). In this decision, dual participation is defined as an instance in which a particular customer is already enrolled in a utility's DR program but also bid into the CAISO market, either individually, or through a DR provider. However, it was determined that the major dual participation issues would be settled after "sufficient experience" with PDR given the complexities of direct participation and lack of experience of DR providers in bidding into the market. 

On April 30, 2012, D.12-04-045 was issued that approved DR budgets for 2012-2014 but also confirmed dual participation rules from the previous decision - i.e., duplicative payments for a single instance of load reduction or load drop is prohibited and a single customer enrolled in two programs (one energy, one capacity) shall receive payment only under the capacity program. This decision added that dual participation in two day-ahead or two day-of programs is prohibited. The idea of incremental load reduction was introduced to refer to instances when dual participation in a day-of program causes customers to curtail more load than they otherwise might have. Finally, the decision made important determinations that dual participation does not increase ratepayer costs but instead provides more expansive and flexible DR resources. The IOUs disagreed with the CPUC, favoring simplicity and unreasonably concluding that DR event overlaps would lead to issues with dual participation. Fortunately, the CPUC rejected the IOUs' arguments. 

On December 4, 2012, D.12-11-025 was issued that differentiated two types of dual participation. First, the CPUC allows dual participation in an energy program and a capacity program when a customer participates in two utility-run retail DR program. Second, dual participation is not allowed when a particular customer participates in more than one DR program that is bid directly into the CAISO's markets due to the lack of experience using PDR. To comply with the prohibition established in the second case, the CPUC added details that DR providers are (1) prohibited from enrolling a customer who is already enrolled with another DR provider, and (2) prohibited from enrolling a customer in a DR program involving direct participation in the CAISO market if that customer is already enrolled in a utility event-based DR program. This decision thus inadvertently led parties to believe that the CAISO forbids registered customers from participating in more than one DR program or from having more than one DR provider. 

On December 10, 2013, D.13-12-029 was issued that sought to modify D.12-11-025 to conform to operational realities with the CAISO system, clarify ambiguous language in the decision, and reflect the parties' consensus about a streamlined approach to facilitate direct DR participation in the CAISO's markets. This decision addressed the problem inadvertently created by D.12-11-025 by allowing a DR provider to place a customer account in the CAISO resource registration if the customer is not in another DR provider's confirmed registration during the same period. This decision continued to consider CPP as an event-based program. 

The Rule 24 tariff was subsequently established that governed direct DR participation rules. Related to dual participation, Rule 24 established that customers requesting DR service may not partition the electric loads of a service account among different DR providers. This means that the entire reduction of a service account's electric demand for a DR program must be registered to only one DR provider. Customer service accounts are not precluded from enrolling and participating in multiple DR programs with a single DR provider but are prohibited from simultaneously enrolling and participating in the event-based DR programs of more than one DR provider. During an overlapping event in two or more DR programs for a single DR provider, the customer's load reductions may not count more than once for payment or other counting purposes. Rule 24 also prevents utility program staff from sharing information to ensure competitive neutrality, which heightens the issue of double counting and paying. 

On November 30, 2015, D.15-11-042 was issued that established that requiring LSEs to attribute the load impacts of dual-participating customers only to the capacity programs resulted in underestimates of the cost-effectiveness of the energy programs. The decision provided three options to assess the cost effectiveness of programs that allow dual participation, with the decision ultimately deciding to use the first methodology:

1. Requiring an additional analysis of both the capacity and energy programs combined

2. Including dual-participating customers in separate analysis of each program, taking care not to double count when calculating the portfolio analysis

3. Requiring an additional analysis of only the dual-enrolled customers in both the capacity and energy programs

2018-2022 DR Application

On December 21, 2017, D.17-12-003 was issued that recounted the precedent decisions on dual participation and established that the CPUC should supplement the record on the dual participation issue ahead of the February 2018 workshop. 

On February 13, 2018, a workshop was held to discuss current DR dual participation rules (as presented by the IOUs) and proposals for revising the rules in response to concerns of possible disparate treatment of customers. This workshop is being convened to address potential issues around unequal treatment of dual DR participation rules between utility-administered DR programs and third-party-administered DR programs, as argued by the Joint DR Parties and OhmConnect. These issues include how to ensure that a customer is not paid twice for the same load drop, as the IOUs do not have visibility into third-party program design, and the firewall between IOU employees who process CISR-DRP forms and the staff that operate IOU DR programs. Another key barrier to dual DR participation is that CAISO rules stipulate that one cannot have the same service account participate with two different DR providers, though one can have two different resources at the same location (retail service account). This is an important opportunity to completely reform the rules.

On June 15, 2018, a Ruling was issued that posed questions for stakeholder feedback on dual participation rules. There has been a history of decisions on dual participation in DR programs over the years. The current DR rules are summarized below:

• Customers are not paid twice for the same load reduction

• One program is day-ahead and the other is day-of

• Only one of the two programs may pay a capacity payment

• If both programs offer energy payments, one of the energy payments must be withheld for simultaneous events

• CPP rate is a day-ahead energy program

The categorization of DR programs and mechanisms are below.

With the rules above, CESA has identified the following dual participation that is generally allowed or prohibited along with the reasons:

CESA recommended that the principles and incrementality definitions from the MUA Working Group should be incorporated into the policy discussions in this proceeding to refine (and potentially reset) the dual participation rules for DR resources. In response to specific questions in the Ruling, CESA explained that the single DR provider requirement under Rule 24 can be addressed through information/data sharing between IOUs and third-party providers to support load forecasting/scheduling and avoid double counting load drops. A modest change in Rule 24 to focus on DR providers of CAISO-integrated DR programs should immediately enable dual enrollment of CPP and third-party DR programs (such as DRAM).

See CESA’s response on July 20, 2018 on the Dual Participation Ruling

Other parties also filed responses that focused mainly on the existing dual participation rules to make the case for why certain dual participation scenarios are prohibited. PG&E appeared to be open to discussing these issues in workshops, including a proposal to establish a ‘statement of principles’ to overcome the Rule 24 ‘firewall’ and only allow the use of third-party DR participation data for performance evaluation and settlement purposes only, while the Joint DR Parties proposed an achievable process for dually-enrolled DRAM/CPP resources to only count the DR resource in load scheduling and settlement when not cleared in the day-ahead market. SCE and ORA, meanwhile, supported the reclassification of the CPP Program as a capacity program given that payments to CPP customers for energy reduction during events are based on the marginal generation capacity cost. SCE also responded that the amount paid through DRAM must be capped for CPP dual-participating customers to avoid paying twice for the same load drop due to the lack of visibility to know if and when DRAM resources were dispatched. SCE explained that DRAM DRPs are not required to perform load impact protocols to receive RA credit, which is in part due to the fact that DRAM is a pilot

CESA responded to other parties’ comments along the following lines:

• A workshop should be held to discuss how the broader MUA principles can be used to comprehensively reform the dual participation rules for DR resources.

• Data on disenrollment from the Critical Peak Pricing (“CPP”) Program to register under a third-party DR program must be viewed in context.

• A workshop should be held to discuss solutions to allow for information sharing between utilities and third-party DR providers.

• The "energy program" categorization of the CPP Program should be maintained.

• A workshop should be held to discuss dual participation rules for customers of utility and Community Choice Aggregator (“CCA”) DR programs.

See CESA’s replies on August 3, 2018 on Dual Participation Ruling.

On October 25, 2018, a PD was issued that set a prohibition of dual participation of CPP and another DR program for all new customers, effective immediately and until further notice. CESA disagreed with the PD and argued that the CPUC should authorize dual participation around CPP and DRAM by addressing the firewall requirement and that a new and separate rulemaking for MUAs should be opened to holistically address dual participation issues and align with broader principles. CESA also recommended that grandfathering should be extended to “legacy” contracts that were executed at the time when dual participation of CPP and LCR contracts were allowed.  

See CESA’s comments on November 14, 2018 on the Proposed Decision

DRPs generally agreed with CESA on how the dual participation rules would be detrimental to MUAs. The IOUs generally supported the dual participation rules but requested that they be given until May 1, 2019 to implement the IT changes and tariff updates. Notably, PG&E did indicate that it was open to considering a standalone MUA proceeding to address these issues holistically. Given the changes involved in implementing the prohibition, CESA has some concerns that a reversal to allow dual prohibition may face headwinds at least until the next DR season in 2020.

On December 10, 2018, D.18-11-029 was issued without any material changes from the PD. The prohibition of dual participation was justified on the grounds that CPP enrollments are decreasing, future of DRAM is uncertain, few customers would be impacted, changes would require costly IT costs, and changes would increase complexity of already complex rules. The decision also detailed how enabling greater dual participation as proposed by parties would require modifications or elimination of the firewall requirement and other established dual participation rules. Due to concerns of an uneven playing field between IOUs and third-party DR providers, the decision also prohibited all forms of dual participation of CPP customers with another utility-administered or third-party-administered DR program, with only already dual-participating customers allowed to do so. The decision also punted on the issue of whether storage providing LCR capacity can be incremental to any DR program.

Load Shift Working Group (LSWG)

Background

On November 1, 2017, D.17-10-017 was issued that established two working groups (Supply Side Working Group and Load Consumption Working Group) to work toward status reports and final reports to inform a future rulemaking (Phase 4) that considers new DR models. R.13-09-011 was closed.

The Load Consumption Working Group (later renamed the Load Shift Working Group) was also established and tasked with producing quarterly status reports and a final report by January 31, 2019. With the help of an expert outside facilitator, this working group was to begin meeting no later than January 31, 2018.

This working was tasked with the following:

• Define and develop new products including load consumption and bi-directional products;

• Develop a proposal of whether and how to pay a capacity value for load consuming and bi-directional products to provide to the RA proceeding;

• Develop a list of data access issues relevant to new models that should be addressed prior to launching new models;

• Develop a proposal on how to better coordinate the efforts of the California Independent System Operator (CAISO) and the Commission;

• Identify the value of new products to provide to the RA proceeding; and

• Consider an appropriate energy storage emissions metric as part of any proposals involving energy storage (from Decision modifying D.16-09-056)

CESA recommended that the Load Consumption Working Group closely coordinate with the CAISO on the development of a wholesale bidirectional DR product while also developing a retail load consumption product. CESA also called for this Working Group to resolve dual participation barriers.

See CESA's comments on October 5, 2017 on the Proposed Decision.

Load Shift Working Group

The CPUC selected Gridworks to facilitate the LSWG to advance toward a final report on January 31, 2019, with quarterly reports delivered on April 15, July 16, October 15, and January 15.

On February 28, 2018, the LSWG held a working group meeting to set the context for the new load shift product. LBNL began with an overview of the Shift DR concept, which is intended to move electric loads from one time to another where Shed DR is offset with an equivalent ‘take’. This shed/take cycle could occur over a period of a few hours over a diurnal cycle, or even across several days. LBNL characterized Shift DR as being either a dispatchable resource (e.g., a CAISO market product) or persistent load reshaping through long-term changes in behavior (e.g., TOU pricing, incentives). LBNL measured Shift DR as an energy product (kWh-year). PG&E presented on the XSP Pilot, which tested the capabilities of demand-side resources to increase load during times of overgeneration on transmission and/or distribution lines, as well as during times of low or negative prices. These events are out-of-market and are simulated by PG&E with pilot participants selecting four-hour blocks (up to two consecutive hours) on when they are available to increase load. A base incentive amount (up to $10/kW-month) are paid based on nominated amounts and adjusted for performance. PG&E found that shorter availability windows provided participants with greater certainty on potential calls and allowed them to factor in retail demand charges into their bidding behavior. PG&E also successfully applied a reverse 10-in-10 baseline methodology. However, PG&E remained concerned about identifying triggers other than CAISO wholesale prices, assessing the impact on rate designs, and assessing the impacts to the distribution system.

On March 21, 2018, the LSWG came to an overall agreement at a high-level around the LBNL definition of “load shift” as aligning shiftable load with renewable generation, with energy neutrality not necessarily being a defining characteristic, such that “take” and “shed” needs may be asymmetric. Additionally, the LSWG agreed that the end-product should be technology neutral, reflect grid needs from the integration of renewables, and be integrated in the CAISO market. SCE and CLECA presented on some preliminary ideas for a load shift product. SCE proposed a load bid concept to encourage more elastic loads that can respond to CAISO prices incremental to the pricing effects of TOU rate implementation. CLECA, on the other hand, proposed a pilot retail program similar to SDG&E’s vehicle-grid integration (VGI) rate that is informed by the CAISO’s day-ahead price, which CESA views as being potentially out of scope given the CPUC’s intent to not consider retail rate options here.

On April 18, 2018, the LSWG worked to unpack the grid needs that could be served by a load shift product and what the possible operational requirements could be. E3 and LBNL presented on the respective results for Shift DR in the IRP and the DR Potential Study, which found that renewable balancing challenges are not significant enough to justify payments to flexible loads at less stringent GHG targets. At more stringent targets, however, more frequent renewable curtailment creates more value to incent load shifting. The CAISO highlighted case studies of operational and flexibility needs where solutions are being developed in the FRACMOO and Day-Ahead Market Enhancements initiatives, while PG&E presented on how it tied grid needs with operational requirements in terms of duration (4-hour availability, up to 2-hour dispatch, option for weekend participation), response time (day-ahead dispatch), size (30 kW), and frequency (1 start/day) in their XSP Pilot.

On May 23, 2018, a meeting was held where the LSWG participants shared their concept proposals on how the ESDER Phase 3 enhanced PDR product can be supplemented to be technology neutral. The meeting began with a discussion of the matrix of grid needs that could be addressed by a new load shift product and an updated oversupply analysis conducted by PG&E. While additional research will be needed to develop locational granularity, PG&E presented a heat map of the average MW by hour per month of when the CAISO’s non-dispatchable GHG-free generation exceeds the CAISO load during 2018, 2022, 2026, and 2030 using publicly-available data from the IRP. However, the CAISO noted that it optimizes at the system-level, not the sub-LAP level.

Next, the LSWG meeting shifted toward a discussion on the CAISO’s proposed PDR-LSR product. The Joint DR Parties presented on how the PDR-LSR framework can be adapted to allow all technologies to register with both a curtailment and consumption resource ID and to measure and net out typical use from approved baseline calculations. One of the key issues with adapting the PDR-LSR product to allow just load consumption was whether it was reasonable to incentivize potentially wasteful and unproductive consumption (i.e., the “stadium lights” problem). Some stakeholders highlighted how certain retail rates, such as those including demand charges, may deter participants from wasteful consumption and how “sophisticated users” may also be participating in DR programs. Meanwhile, the issue of baseline calculations was also brought up. Currently, the 10-in-10 baseline method is used, but some stakeholders raised that it will be difficult to identify 10 typical-use days with more frequent dispatch of DR resources. For energy storage resources, overly frequent dispatch may also create battery degradation risks. In addition, stakeholders raised the question of whether submetering requirements are necessary for non-storage DR resources and whether baseline calculations can be done instead by premise. The IOUs noted, however, that this would raise settlement challenges where meters (that currently read in 60-minute intervals for residential customers and 15-minute intervals for non-residential customers) would need to be reprogrammed to read 15-minute and 5-minute intervals, respectively, which will not be rolled out until 2020 at the earliest.

Finally, Gridworks presented a draft work plan, proposing which topics will be covered the remaining LSWG workshops. Discussions during the meeting revealed that there is still lack of clarity on the “market integration” requirement of the new load shift product, as well as on the operational requirements and the consideration of how the product will evolve as grid needs also evolve over time. Overall, the LSWG seems to have difficulty in defining what the load shift product would be needed for at the distribution and retail levels, continuing to rely on exploring the landscape of work done previously in pilots, CPUC proceedings, and CAISO initiatives.

On June 19, 2018, the objective of the LSWG meeting was to develop performance evaluation methodologies on the new load shift product, leveraging the lessons learned and insights from the Baseline Analysis Working Group (BAWG) from the ESDER Phase 2 Initiative and PG&E’s Excess Supply Pilot (XSP).

First, SDG&E presented on alternative baselines developed in the BAWG, mainly for residential customers featuring day-matching, weather-matching, and control group analysis. Day-matching baselines generate counterfactuals with proximity to event day using a 10-in-10 method, where 10 of the most recent, similar non-event days (either business or non-business days) during the last 45 days. If 10 non-event days are unavailable, then the highest 5 event days are dropped. There is also a capped adjustment factor considering the consumption in the “pre-event window” and “post-event window” before the event in order to capture the additionally high actual baseline of event days. Weather-matching baselines generate counterfactuals with non-event days with similar temperatures, regardless of date proximity. Weather-matching goes 90 days back, excluding event days and non-similar days. The four days closest to the highest weighted temperature of the event day are considered “similar” days. Control groups generate counterfactuals using randomized control trials with real-time data from residential customers, where DR providers are allowed to decide their control group among participants. This methodology works for “flat rate” DR programs like AC cycling programs but it is hard to implement for performance-based payments. Participants responded favorably to the first two options but were skeptical of the usefulness of employing control group methodologies. For example, participants highlighted how extended adjustment windows can be affected if there is a load increase and decrease on the same day. Additionally, data can be biased toward high price (decrease) days while frequent dispatches can pose issues for day matching.

Second, PG&E presented the first (exploratory) phase of research on the use of over 50 alternative day- and weather-matching baselines to be applied to load increases. PG&E used machine learning and statistical methods to identify the “best fit” baselines. Participants expressed interest in contributing with research questions for further phases but highlighted potential limitations of the dataset using hourly meter data from just PG&E customers. 

Finally, the CAISO presented on the baseline implications of the premise, device, or both participating as PDR resources, using ideas developed for the PDR-LSR product in ESDER Phase 3. Similar to the 10-in-10 baseline methodology, the CAISO has proposed to use a baseline created from looking at the same interval (15-minute increments of data) on similar, non-event days over a 45-day look-back window. Using a shorter interval takes into account how BTM energy storage devices may not charge or discharge constantly over an hour. This accounts for both curtailment and consumption events. Importantly, negative baseline results are capped at zero, as shown in the example below.

The proposed methodology above partially solves the issue brought up in CESA’s incrementality report by adjusting the baseline for bidirectional DR. However, participants were worried about the methodology’s assumption that behavior during non-market intervals was uncorrelated from behavior during market intervals – e.g., energy storage charging in anticipation of a curtailment DR event. They were also concerned about the ability of creating a technology-neutral product given that this methodology clearly favors quick-dispatch technologies, such as energy storage.

On July 18, 2018, a LSWG meeting was held to refine thinking around load bidding, variations of the PDR enhanced model, and plans to consider an energy storage GHG emissions metric for any energy storage related proposal. First, on load bidding, PG&E and SCE presented on how each LSE currently bids in 10 “steps” with combinations of quantities and prices in the day-ahead market. Once all bids are in, load below the market clearing price is purchased at the clearing price while the rest of the load is priced and purchased in the real-time market. As it is operated now, demand bidding does not capture the nuisance of discrete operational characteristics (e.g., ramp rate, max/min run times). The load bidding idea would thus be a previous step to real-time pricing and would require participant submission of bids through the LSE. Furthermore, load bidding could only be done at the DLAP and would not be able to be dispatched for sub-LAP needs. However, questions were raised around baselines and how the real pathway may be retail-level real-time pricing. Since load bidding would require close coordination with an LSE, there may be significant transaction costs and thus may not be open to all parties. The LSWG brainstormed four potential pilot ideas:

• Real-time signal: Load would respond to a continuous price or GHG signal, or customers respond to real-time prices passed through.

• Pay for load shape: A customer would be paid to conform their load to a target load shape that is beneficial to the system (e.g., anti-duck shape) and/or applied to the geographic area of a distribution feeder.

Finally, Stem presented on the GHG emissions metric for energy storage, which depends on the usage of the technology. Stem provided background on the history of the GHG emissions metric in SGIP as well as linkages to the prohibited resources decision (D.16-09-056), and how energy storage is not an inherently clean or dirty technology. In California, GHG emissions are largely correlated with price since renewables are setting the marginal price, with some exceptions. In conclusion, Stem discussed how the GHG emissions factor for storage should be balanced against the other factors and objectives of DR programs to maintain technology neutrality and achieve broader policy objectives.

On August 9, 2018, a draft evaluation framework prepared by Gridworks was presented to provide a consistent basis for comparing the possible load shift product options and to judge the merit of the products under CPUC guidance that the product is market integrated, not a rate, and not directly related to DR serving a distribution deferral service. In addition to this guidance, the framework also creates placeholders for dispatch requirements, organizational roles, settlement processes, grid and policy needs match, and customer experience, among other product specifications and implementation details.

On August 22, 2018, the LSWG refined the evaluation framework to compare the different products. CLECA presented on their refined thinking on the Critical Consumption Period pilot, which will be:

• “Informed” by the day-ahead market pricing when the nodal prices are negative

• Dispatched over 1-6 hours

• Compatible with BIP

• Be an energy-only product

• Settled based on a 10-in-10 baseline

• Replace the Demand Bidding Program (DBP)

• Applicable to IOU, CCA, and DA customers

Finally, the LSWG discussed the possible impacts of the load shift product on the distribution system. The location, size, concentration, timing, duration, and response speed will all factor in when considering the impact of a load shift product on the distribution system. Gridworks also shared their update on the group’s workplan.

On September 17, 2018, a meeting was held to refine thinking on the CAISO’s PDR model for load shift and RA. CPower presented on potential enhancements to the PDR-LSR product that was approved by the CAISO Board on September 5 to make it technology neutral. Some of the key changes to the PDR-LSR would be to make the product at the premise level, use baselines adopted in ESDER Phase 2, and use the hourly block intertie bidding option.

On October 24, 2018, a working group meeting was held to provide updates on sub-group discussions around RA, GHG emissions, and load shift product proposals. The RA sub-group provided updates on what recommendations should be made in and outside of the RA construct to incentivize load shift and verify its performance. The GHG sub-group provided an update on how each product should indicate how it could impact GHG emissions by answering whether the product is market integrated or only dispatched during negative pricing intervals, and if it is not market integrated, how the GHG emissions would be tracked. Gridworks highlighted product similarities (i.e., technology neutral, energy neutral, assumed to allow for multiple uses) as well as differences (e.g., dispatch granularity, performance evaluation). The group discussed the difference between dual participation (i.e., participating in two different DR programs) and multiple-use application (i.e., providing different services to different entities using different capacity and/or at different times).

On January 31, 2019, the final LSWG report was submitted to the CPUC that proposed a number of new products based on LSWG's interpretation of the DR goal and principles for DR laid out in D.16-09-056:

• Load Shift products should be technologically neutral, open to all sources and end uses.

• Load Shift products should reflect grid needs, especially integration of renewables, while accounting for customer needs and capabilities.

• Load Shift should not be "one size fits all" - i.e., different customer classes, technologies, business models, and stakeholders have value to add and should be encouraged.

• Load Shift may include both "take" and "shed" and the two may be asymmetric - i.e., a requirement that any take be offset by an equal shed ("energy neutral") is technologically impractical for actual end uses for CAISO's market optimization and not necessarily representative of grid needs.

Using these principles, the LSWG proposed six products that met its evaluation criteria and included details on the product description, dispatch method and granularity, grid needs, potential costs, customer accessibility, performance evaluation, GHG impacts, and regulatory readiness. following proposed products:

• Load Shift Resource (LSR) 2.0 builds on the CAISO's PDR-LSR product to be available to all technology types, not just energy storage, so long as CAISO participation and real-time/day-ahead dispatch requirements are met. This product would be fully market integrated and dispatched by the CAISO at either the sub-LAP or Pnode level in 15-minute or hourly blocks, with the "take" being done during negative or low prices. To the extent LSR 2.0 is determined to provide benefits beyond wholesale energy, the CPUC may consider incentives commensurate with that value. ESDER Phase 2 baselines could be used for performance evaluation. However, this would require the ESDER Initiative to take this up.

• Critical Consumption Period product is a retail load increase DR product triggered directly by the LSE and paid based on negative wholesale day-ahead nodal market prices. The customer would have the negative or low real-time wholesale price passed through to the customer, though they would continue to pay the non-energy components of the retail rate. A monthly participation incentive could be considered as well given that energy prices may not be significantly negative. As a market-informed product, the LSE would settle the dispatch at the Pnode in hourly intervals. Similar to the XSP Pilot, a reverse 10/10 baseline could be used for load increase, but questions around the impact on non-coincident demand charges was raised.

• Market Informed Demand Automation Service (MIDAS) encompasses a variety of potential demand automation services deployed by vendors utilizing either a market or grid state informed signal (e.g., GHG signal) that is acted upon by a controller connected to an end-use via an API. MIDAS customers are responsible for providing the end-use devices and the preferences regarding how the device is controlled. The MIDAS product would be dispatched outside of the CAISO market and thus would require the LSE to anticipate and incorporate the change in load into a load bid in the CAISO market over time as behavior was observed. Third parties would take actions on the customer's behalf to optimize for the customer's preferences. No settlement process is envisioned in the first version of this product, as the retail customer is compensated by either bill reduction or by emissions reduction.

• Market Integrated Distribution Service (MINTDS) builds on LSR 2.0 but is dispatched on a day-ahead basis at the circuit-feeder level and paid with distribution capacity payments to meet distribution system needs, with wholesale market dispatch as a secondary attribute. With a distribution focus, MINTDS is focused on mitigating reverse power flow and improving voltage management that ultimately serve to accommodate more DERs. This product should also be targeted for distribution needs that align with CAISO market needs. A tariff and other policy changes may be needed. Any Load Shift not needed for distribution capacity could be dispatched in the CAISO market.

• Pay for Load Shape (P4LS) includes a range of market-informed approaches that could be used to provide target load shapes (for an LSE and/or UDC) that are updated periodically or seasonally (e.g., every 3 months) based on evolving grid needs. Customers who are participating in the program would modify their loads, either at the site-level or in aggregate, and be compensated for the response relative to the target (e.g., energy market savings, capacity cost savings). There is a challenge in calculating the incentive value, the performance criteria, and the policy design options related to balancing the need for complex baseline estimates with the risk of paying incentives to sites whose loads are already aligned with grid needs. LSEs would also need to establish methods for forecasting the cost and emissions related to serving customer loads to then develop target load shapes.

• Distribution Load Shape (DLS) resembles P4LS with a specific additional distribution service dimension, where customers would permanently provide Load Shift according to a defined schedule, offered by the utility through a tariff. Reflecting 'duck curve' needs, this resource will be market informed and follow a pre-determined schedule via a rider tariff. Where the distribution needs correlate with system needs, the DLS product will provide renewable curtailment and peaking capacity benefits as well.

Based on the products above, the report highlighted similarities in the products around technology neutrality, the expectation to serve multiple grid needs, and the feature of energy asymmetry but also found key differences in dispatch method/granularity, role of the IOU and aggregators, and regulatory readiness. Market-informed approaches were noted as presenting costs and complexity of market participation. One challenge that was highlighted around the renewable curtailment and GHG impacts of any Load Shift product was around the ability of such resources to be consistently available at the time and place needed and effectively handled by the forecaster, given the potential for unintended impacts of forecast uncertainty on dispatch in the market (e.g., positive prices despite forecasts of negative pricing). The report recommended that the CPUC conduct pilots with active testing, oversight, refinement, and valuation to help bring Load Shift DR as a mature and tested resource for the grid. 

Several regulatory barriers were identified in the report. An important barrier was the ability of Load Shift to reduce flexible ramping needs by raising the minimum load of the grid and to provide Flex-Down RA, but questions were raised around the need to unbundle RA services and to introduce performance requirements (e.g., telemetry, response time, response duration) if Load Shift resources were to receive some RA payment. Regarding GHG impacts, the report found no need for additional emissions metrics for market-integrated products given the strong correlation between negative prices and GHG emissions in the CAISO markets and determined that it may be okay to punt on this issue for now even for market-informed products, given the work being done in the SGIP proceeding.

Demand Response (R.13-09-011)

Policy Development

On December 9, 2014, D.14-12-024 was issued that included a policy statement that fossil-fueled backup generation resources would not be allowed as part of DR programs for RA purposes and directed the IOUs to gather information about the use of backup generation by non-residential customers. 

On September 29, 2015, a Ruling was issued that introduced a Staff Proposal that defined fossil-fueled backup generation to be consistent with the Loading Order and that prohibited the use of such resources in DR activities. The Staff Proposal also recommended enforcement of this prohibition through attestation for residential customers and the use of proration for non-residential customers, the latter who would have two options: select metering or derate their payments to reflect the size of the backup generator. 

On September 29, 2016, D.16-09-056 was adopted that prohibited the use of certain resources (fossil-fueled backup generators) during DR events and provided guidance to the IOUs for 2018 and beyond DR programs. Specifically, the decision prohibited fossil-fueled backup generators in DR programs starting on January 1, 2018. The decision also modified D.14-12-024 to rescind data requirements for fossil-fueled backup generators in DR programs. Non-residential customers would need to either attest to non-use of prohibited resources to reduce load during a DR event, or would need to accept a default adjustment value (DAV) to their incentive payments in cases where a prohibited resource was used for safety reasons. This list of prohibited resources would include:

• Diesel-based distributed generation technologies

• Natural gas

• Gasoline

• Propane

• Liquefied petroleum gas

The following resources would be exempt from the prohibition:

• Pressure reduction turbines

• Waste-heat-to-power bottoming cycle combined heat and power (CHP)

• Energy storage and storage coupled with renewable generation (that meets the GHG emission standards adopted in SGIP)

On January 26, 2018, Stem filed a Petition for Modification (PFM) requesting that energy storage be removed from the list of prohibited resources. Stem also argues for the elimination of the requirement that energy storage resources used for DR programs meet the GHG emissions standards adopted for SGIP, at least until the CPUC adopts recommended changes from the SGIP GHG Signal Working Group. Alternatively, Stem recommends that an appropriate GHG emissions standard be developed without reference to SGIP. The flawed metric and requirements in SGIP and the impact of these requirements on non-SGIP projects are cited as reasons for the modifications requested in the PFM. As the PFM notes, this policy may have an unintended impact of precluding energy storage from providing DR services in the DRAM or in accordance with LCR contracts. CESA submitted a response in support of the PFM given the efforts underway to review and update the current ‘flawed’ SGIP metrics and requirements, which once approved, can then be considered for use in DR programs as an eligibility requirement. CESA also echoed Stem’s concerns around the potential unintended impacts of precluding energy storage resources from providing DR services in accordance with LCR and DRAM contracts in addition to its provision of new DR services and products. While supportive of the GHG emission requirements of DR programs, CESA cautioned against uneven GHG emission reduction requirements for energy storage resources as compared to traditional DR resources. CALSSA and the Joint DR parties agreed with CESA in supporting the PFM, but PG&E, SCE, and ORA submitted a response in favor of continuing to use the RTE factor in the interim to identify prohibited energy storage resources. While ORA recognized that the SGIP GHG standard should only apply to SGIP-funded systems, it supported continued use of the current SGIP GHG standard until a DR-specific GHG emissions standard for energy storage systems is developed and adopted.

See CESA's response on February 26, 2018 on the PFM

On May 15, 2018, a PD was issued that affirmed Stem’s PFM. CESA supported the PD but added that the CPUC should careful interpret the study results and recommendations from the SGIP working group and that the CPUC should consider CESA’s previous comments on exempting energy storage from the prohibited resources policy due to the lack of source emissions from energy storage technologies.

See CESA's comments on June 4, 2018 on the Proposed Decision

On June 27, 2018, D.18-06-012 was issued that affirmed Stem’s PFM requesting that energy storage be removed from the list of prohibited resources, until a review during a rulemaking on new DR models or the 2023-2027 DR applications. The CPUC determined that the prohibited resources policy should not include requirements associated with SGIP because grid reliability could be jeopardized (i.e., LCR contracts for energy storage DR), SGIP responds to retail rates whereas DR responds to market rates, and SGIP is expected to sunset in 2020. Importantly, the decision made a nuanced distinction on how energy storage is exempt but not excluded from the prohibited resources policy, especially because the CPUC affirmed CESA’s viewpoint that energy storage resources should not have to comply with stricter operating requirements as compared to traditional DR resources. The decision was not substantially changed from the May 15, 2018 PD except that the LSWG is being directed to develop the appropriate GHG emissions metric for energy storage resources participating in DR programs. The decision also closed this proceeding as the other outstanding DR issues will be addressed in the 2018-2022 DR Applications.

Implementation

On April 27, 2017, the CPUC approved Resolution E-4838, which restricts prohibited resources (e.g., backup generators) from participating in the 2018 DRAM III pilot, along with the corresponding modifications to the auction design, protocols, standard pro forma contract, and evaluation criteria. Three attestation scenarios were outlined, and two types of violations were prescribed: Type 1 violation involving minor clerical or administrative errors that could be resolved with an updated attestation submitted within 60 days of violation occurrence; or Type 2 violation involving the use of a prohibited resource despite attestation to not do so, which would lead to removal from DR program and all DR programs for one year for the first Type 2 violation and for three years for two or more Type 2 violations. 

On September 1, 2017, each of the IOUs filed advice letters to implement their Prohibited Resource Audit and Verification Plans. Most of this new policy involved customer attestation processes for verification that resources participating in DR programs are not used just for back-up generation. The IOUs proposed three attestation scenarios for the verification process:

• Attestation Scenario 1: Customers attest to not having a prohibited resource on-site.

• Attestation Scenario 2: Customers attest to having a prohibited resource on-site but that they will not use it to reduce load during a DR event.

• Attestation Scenario 3: Customers attest to having a prohibited resource on-site for use during DR events for safety, health, or operational reasons, but are asked to provide the resource's total nameplate capacity for use for the DAV to adjust the DR incentives.

On January 24, 2018, Draft Resolution E-4906 was issued that approves, with modifications, the IOUs’ plans for implementing prohibited resource restrictions in their DR programs and directs the IOUs to file a joint application for a pilot program for measurement and verification technologies (e.g., meters, data loggers) and for the administrator contract. The purpose of the prohibited resources policy is to ensure that distributed generators are not participating in DR programs to provide backup services. Thus, this resolution is intended to implement an attestation and verification process for customers to ensure that fossil-fueled generators are not being used for load reduction as part of the IOUs’ DR programs. These attestation forms and processes would apply to participants of the DRAM starting in the 2020 DRAM cycle. Importantly, the Draft Resolution disagreed with the IOU advice letters in not requiring every DR customer to install costly data loggers or interval meters upon the IOU’s request, and instead only required that customers “attest” to the conditions of DR program participation, with the potential for IOUs to verify compliance. Attestation Scenario 1 and 3 customers would be randomly sampled and verified by program, while 10% of the Attestation Scenario 2 customers would be included in a one-year pilot involving the installation of ratepayer-funded meters and loggers. The Draft Resolutions was reluctant to mandate meters and loggers, contrary to ORA and environmental groups’ recommendations, due to the uncertainty of their costs and the total incentive payments to customers.

On June 21, 2018, Resolution E-4906 was issued after being held at multiple CPUC voting meetings. The Resolution approved, with modifications, the IOUs’ plans for implementing prohibited resource restrictions in their DR programs and directed the IOUs to file a joint application for a pilot program for measurement and verification technologies (e.g., meters, data loggers) and for the administrator contract. Thus, this Resolution was intended to implement an attestation and verification process for customers to ensure that fossil-fueled generators are not being used for load reduction as part of the IOUs’ DR programs. These attestation forms and processes would apply to participants of the DRAM starting in the 2020 DRAM cycle. Importantly, the Resolution disagreed with the IOU advice letters in not requiring every DR customer to install costly data loggers or interval meters upon the IOU’s request, and instead only required that customers “attest” to the conditions of DR program participation, with the potential for IOUs to verify compliance.

• Attestation Scenario 1: For customers in the sample who attest to not having a prohibited resource on-site, the verifier would check the attestation against utility interconnection and notification records for prohibited resources. If there were no records found, the verification administrator would then submit a data request to the relevant air quality management or air pollution control districts to compare the customer’s attestation against the permit records.

• Attestation Scenario 2: Customers in this sample attest to having a prohibited resource on-site, but that they will not use it to reduce load during a DR event. For customers with generators greater than 37 kW, the verification administrator would request a written operating log and a photo of the generator’s hour meter. The verification administrator would then check these operating logs against DR event dates and outage data. For customers with generators less than 37 kW, the customer would be required to install a data logger, at the customer’s expense, as a condition of participation.

• Attestation Scenario 3: Customers in this sample attest to having a prohibited resource on-site for use during DR events for safety, health, or operational reasons. As part of the attestation, they are asked to provide the resource’s total nameplate capacity, which will be used as the Default Adjustment Value (DAV) to adjust the DR incentives for that customer’s service account. For these customers, verification administrator would compare the attested nameplate capacity against Utility interconnection and notification records. If such records are not found, the verification administrator will submit a data request to the relevant air quality management or air pollution control districts to compare the customer’s attested nameplate capacity against the permit records

Attestation Scenario 1 and 3 customers would be randomly sampled and verified by program, while 10% of the Attestation Scenario 2 customers would be included in a one-year pilot involving the installation of ratepayer-funded meters and loggers. The Resolution was reluctant to mandate meters and loggers, contrary to ORA and environmental groups’ recommendations, due to the uncertainty of their costs and the total incentive payments to customers. The Resolution prescribed consequences for two types of violations or non-compliance with the attestations:

• Type 1 Violation: Minor clerical or administrative errors that may be resolved with an updated attestation and do not involve the use of a prohibited resource to reduce load during a DR event. Existing customer has 60 days from date of notice to cure non-compliance. If an attestation is not submitted within 60 days (uncured non-compliance), the customer will be removed from the DR portfolio until an attestation is provided

• Type 2 Violation: Using prohibited resource(s) to reduce load during a DR event despite attesting to not doing so, and/or submitting an invalid nameplate capacity for the prohibited resource(s). A single instance of non-compliance will result in customer removal from the schedule and ineligibility to enroll in any DR program for 12 calendar months from the removal date. Two or more instances will result in the same removal and ineligibility terms for three years.

The Draft Resolution was modified in the Final Resolution to require the IOUs to inform and sign agreements with third-party aggregators before making information requests to the customers and to require the number of resources (in addition to nameplate capacity for all resources) to be reported in Attestation Scenarios 2 and 3. Furthermore, since the approval of the Resolution was delayed and the original intent was to implement the prohibited resources policy by January 1, 2018, the Resolution adopted an advice letter process for tariff changes as well as time for IT system changes and outreach efforts to be likely approved by September 11, 2018, followed by attestation submissions by third-party DR aggregators due by December 10, 2018, in order to have the prohibition policy in place by January 1, 2019. The IOUs will have until April 5, 2019 to install the interval meters and data loggers for its pilot.

On July 23, 2018, the IOUs filed a joint supplemental advice letter that proposed a Final Prohibited Resource Audit Verification Plan in accordance with Resolution E-4906. The IOUs will hire a single verification administration (VA) for all verification activities across affected DR programs, including the DRAM. 

On December 21, 2018, the CPUC issued a non-standard disposition letter that approved each of the IOUs advice letters and supplemental advice letters pursuant to Resolution E-4906. In particular, the CPUC approved of SDG&E’s removal of the requirement that data logger and verification metering for direct-enrolled customers to be at the customer’s expense.

Meters & Loggers Pilot

On October 19, 2018, the IOUs each filed an application to develop a record on the cost and functionality of revenue-grade meters, non-revenue-grade meters, data loggers, and installation costs to support the CPUC’s determination of the use of loggers and meters in the prohibited resources verification plan. This application is part of the evaluation process for the one-year pilot to be conducted in 2019 to install meters and loggers on 10% of Attestation Scenario 2 customers. The application provides information on the range of interval meter and data logger models, their functionalities, and associated unit and installation costs.

On December 6, 2019, a workshop was held on the pilot report of interval meter and data logger installations pursuant to the prohibited resources policy for DR programs and prepared by Nexant. Started in the Spring of 2019, the Metering Pilot resulted in the installation of data loggers and interval meters at 38 customer premises located throughout California and across all IOU service territories, meeting the requirement for the pilot to include 10% of the eligible population of DR participants (i.e., 345 total service accounts or premises). The devices were placed in the field prior to the dispatch of any summer DR program events and the devices were removed the first week of October 2019. A total of 58 data collection devices were deployed in order to monitor a total of 56 prohibited resources (i.e., backup generators, fuel cells) encountered by the field technicians and electricians.

Nexant found that three prohibited resources were operational during DR events in Summer 2019. While the fuel cells were constantly operational, their operation observed during the DR event hours was not for the purposes of producing DR load reductions and was no different than non-event days. However, for a third prohibited resource, they were found to be operating and serving load during DR event hours and thus in violation of the prohibited resources policy. Nexant also provided several recommendations on the IOUs’ verification plan:

• The Verification Plan should be amended to require that a random sample of DR participants with prohibited resources be selected for monitoring each year.

• Interval meters should be the default monitoring equipment, but data loggers should be used in cases where the installation of interval meters is not possible.

• Electronic interval data records of prohibited resource operation and load service recorded internally by prohibited resources selected for audit should be used in lieu of installing external data collection devices.

• All prohibited resources at sampled customer premises should be monitored.

• Attestation forms should be amended to provide a field for the customer to provide a point of contact that is knowledgeable of their prohibited resources’ operations.

Supply Side DR Working Group

Background

The SSWG is tasked with addressing technical barriers to DR integration into CAISO markets, including minimum size requirements, local RA requirements (e.g., 20-minute issue, minimum run times, maximum run hours, partial de-rate options), qualifying capacity for weather-sensitive DR resources, expensive telemetry requirements, and dual participation issues.

On February 15 and 26, 2018, the working group outlined shorter- and longer-term priorities, laid the scope and schedule of the working group. The working group began to assess the issue around the reliability cap, including whether the cap should be raised, whether the triggers should be adjusted to make the Base Interruptible Program (BIP) available more, and whether to develop a hybrid reliability-economic product that would be dispatched based on a price signal. The IOUs are not advocating for a change in the cap because settlement agreements would need to be changed.

On March 26, 2018, an in-person meeting was held to prioritize and define issues for the SSWG. The SSWG will be in close coordination with the RA proceeding and ESDER Phase 3 Initiative to address issued scoped for consideration in this working group. The following issues were identified as being high priority but with some certainty on being considered at the CPUC or CAISO, though the timing of it is unclear:

• Local RA requirements for use-limited resources

• Partial de-rate options

• Weather-sensitive DR qualifying capacity requirements

• Mismatched supply plans and DRAM showing and counting in year-ahead timeframe

• Multi-year procurement

• Less expensive telemetry requirements

Finally, the following issues were classified as lower in priority with unclear timing or procedural venue:

• Registration of new market participants

• Minimum size requirements

• RDRR day-ahead bidding options

Issue 4 (Less Expensive CAISO Telemetry)

Most DR resources are use-limited and DRPs want the ability to dispatch resources whenever economic in day-ahead and real-time markets. The only way to bid and dispatch DR resources economically in the real-time market is through the use of the PDR product, but PDRs currently require telemetry for resources larger than 10 MW. Telemetry is expensive and requires connectivity maintenance, which increases costs for DRPs. As a result, DRPs may attempt to avoid these costs by integrating resources as RDRRs, which do not require telemetry. Alternatively, DRPs may register their resources in multiple PDRs smaller than 10 MW to avoid the telemetry requirements, but that increases the complexity and number of resources to be managed by the DRP and the CAISO.

On April 23, 2018, SCE brought a special issue up in the SSWG as a high-priority issue where some DR resources are use-limited but restricted from bidding economically in the day-ahead and real-time markets due to the high cost and connectivity maintenance requirement of telemetry in the PDR model for resources larger than 10 MW. SCE proposed to raise the MW requirement for telemetry for PDR resources or to find a less costly alternative (e.g., statistical sampling).

On November 1, 2018, there were discussions to explore less expensive telemetry options. The CAISO mentioned the possibility of a temporary exemption from the telemetry requirement, which is required for PDR resources greater than or equal to 10 MW. A temporary exemption (on a trial basis) for a specified period of time is usually granted by the CAISO to allow for parties to gain experience in operating a non-telemetered PDR.

On February 14, 2019, EPRI shared the insights and results from its investigation into lower-cost telemetry alternatives, including the use of mass-market devices and meter data (e.g., OhmConnect’s data aggregation server). The SSWG discussed whether such software-based metering could meet the CAISO’s requirements. Overall, finding such alternatives will important to enable greater DR participation in wholesale markets. 

Issue 9 (Review of 2% Reliability Cap)

On April 16, 2018, the SSWG quarterly report was filed that discussed how the SSWG reached a general consensus to not revise the 2% cap on reliability DR at this time because it would likely require re-opening a settlement agreement.

On June 15, 2018, a Ruling was issued that detailed observations with respect to the reliability resource trigger, which was established for RDRR resources through D.10-06-034. The settlement adopted in that decision required that the parties not propose a change to the trigger for any year prior to 2015. In the SSWG, the CAISO supported changes to the trigger to allow RDRR be called prior to an emergency and to make RDRR look more like PDR, and the CPUC and ORA were open to reviewing this issue. The CPUC conducted research that found that the CAISO procures exceptional dispatch energy or capacity before calling for RDRR resources. In the post-settlement period, the CPUC found that the CAISO called fewer warnings (1.75 warnings annually) than before the settlement (3.9). The CPUC is considering whether to adopt additional flexibility in the trigger by allowing its use anytime within the "Warning stage" or even prior to the Warning stage - e.g., Alert notice and/or Restricted Maintenance Operations. 

Issue 10 (Minimum and Maximum Run Times)

On June 20, 2018, SSWG participants reviewed and discussed draft report sections for each of the priority issues. With developments in the CAISO’s DAM Enhancements Initiative, the CAISO is proposing to move to 15-minute bidding granularity from the current hourly bid increments, which creates problems for DR resources in meeting the minimum run time requirement for each hour at a constant level, even as the awarded amount can be different for each 15-minute interval in the hour. DR programs often have one dispatch/start per day and must be used for a minimum period of time to provide much value, but being dispatched on and off in sequential 15-minute intervals may not work for many DR programs. The SSWG report proposed two potential solutions to address this issue. One solution may be to adopt options for PDR resources to submit hourly block bids fixed for an hour with 52.5 minutes of notice, as proposed in the ESDER Phase 3 Initiative, wherein the PDR resource would have a fixed schedule and act as a price taker within the hour. A second solution could be to allow supply bids to be submitted in hourly increments in the day-ahead market, where PDR resources would be dispatched in the real-time market if the 15-minute bid is economic and the dispatch notice would come 22.5 minutes before delivery. Furthermore, the lack of maximum run hours per day in the CAISO despite DR programs having a maximum number of event hours per day in place is highlighted as a problem in the report, though no specific solutions are proposed. The draft report also discussed how the lack of commitment costs for PDR resources often leads to a dispatch commitment in the residual unit commitment (RUC) process after the day-ahead market has run, despite PDR resources facing an infeasible dispatch as a use-limited resource. The CAISO indicated that the proposed solutions in the DAM Enhancements Initiative to eliminate the RUC and replace it with an imbalance resource product will provide the ability to submit a non-zero bid in the real-time market, thereby eliminating the infeasible dispatch issue.

On November 1, 2018, the CAISO provided updates on the issue of DR resources lacking commitment costs, leading to RUC dispatch. In the CAISO markets, commitment costs have been used to determine the order of dispatch for resources committed in the RUC process that occurs after the day-ahead market has run. DR resources may readily be given an advisory dispatch commitment after the day-ahead market in the RUC process because they have no commitment costs.  This may occur even if they have relatively high energy bid prices. In the Commitment Cost and Default Energy Bid Enhancement initiative (CCDEBE), the CAISO proposed to allow resources with a zero Pmin to have commitment costs, so they would not automatically be selected first in the RUC process on the basis of a commitment cost of zero.  Furthermore, in the DAME stakeholder initiative, the CAISO proposed to eliminate the RUC and to replace it with an Imbalance Reserve Product (IRP).  The CAISO claimed that this will allow a resource to reflect its marginal cost of its MOO in the real-time market, and that the replacement of RUC and the ability to submit a non-zero bid in the RTM will eliminate the infeasible dispatch problem. However, this raised issues of how well PDRs can determine their marginal cost of their MOOs in the real-time market.

The SSWG also began discussion of the maximum run time issue. Currently, there is no enforcement of a parameter in the CAISO resource data template to specify a maximum number of run hours per day. Many of the IOU DR programs and third-party contracts have a maximum number of event hours per day (e.g., 4-6 hours for IOU programs).  As a result, without a maximum run time, resources are not taken out of the market when they should be.  Therefore, SCE proposed activating and using an existing parameter in the CAISO resource data template to specify a maximum number of run hours per day. The CAISO responded that bidding options were partly addressed in ESDER Phase 3, which allowed PDRs to be bid into market with hourly, 15-minute, and 5-minute minimum run time capabilities. The CAISO also highlighted how PDRs have the ability to utilize the daily energy limit (in MWh) constraints over the day. In the Commitment Cost Enhancements Phase 3 (CCE3), the CAISO said that it will allow opportunity costs to be incorporated into the startup, minimum load, and transition costs for generating resources

On December 5, 2018, a SSWG meeting was held to discuss the maximum and minimum run time issue. SCE presented evidence that it has encountered more than 30 events with the aforementioned issues. To illustrate, SCE presented an example where a 5 MW DR resource is limited to a maximum two-hour event time for a maximum one event per day in an IOU DR program. SCE thus proposed to the CAISO whether a maximum daily run time parameter could be built into its market model and whether a minimum run time parameter could be implemented for resources with a Pmin of zero.

On January 24, 2019, SCE discussed some of the limitations in its DR portfolio. Its Summer Discount Plan (SDP), Capacity Bidding Program (CBP), and LCR contracts each have limitations around the maximum events per day (1 to multiple), hours per day (4-6), and operational hours.

Issue 11 (Local RA Requirements for Use-Limited Resources)

The current RA Program does not fully consider resources' availability limitations, as RA requirements are based on meeting peak capacity needs in terms of MWs. Such resources have limitations in terms of duration hours and event calls responding to a contingency event in a local area. The CAISO explained that the current transmission study process does not consider hourly load and resource analysis, which would allow for more precise determination of energy needs in local areas, similar to what was done for the Moorpark and Goleta areas. 

On June 20, 2018, SSWG participants reviewed and discussed draft report sections for each of the priority issues. The SSWG report touched upon the CAISO’s proposal in Track 2 of the RA proceeding to place limits on the amount of use-limited resources such as DR resources with a four-hour duration that could qualify for Local RA. It is important to note that the CAISO, however, does not currently define DR resources as a use-limited resource. To address the CAISO’s concerns with relying on use-limited resources for Local RA requirements, DR stakeholders presented their views on how DR programs could be run sequentially and dispatched as part of a single resource ID, or could be run in conjunction with energy storage and dispatched as part of a single resource ID to extend the duration of these use-limited resources.

On July 17, 2018, a SSWG meeting was held that began with an introduction by the CPUC to the ELCC methodology and an overview by the CAISO on the variable energy resource (VER) forecasting and market participation model, followed by a presentation by PG&E on current DR Load Impact Protocols (LIPs). The key presentation was made by SCE on how the ELCC methodology could be applied to DR resources, which was observed to be not a simple “plug and play” because of factors like rated capacity and temperature sensitivity. However, SCE noted that LOLE is already being used as part of its A-Factor calculation in determining the incentive value for DR. While A-Factor accounts for program limits for the DR resource, it does not factor in the magnitude of load reduction. The A-factor represents the percentage of LOLE hours that can be captured by the DR program after taking into account program limits (i.e., program hours, duration limits, frequency limit). The A-factor for SCE’s Summer Discount Plan (SDP) resource is 98%. The ELCC value for a sample SCE DR resource was calculated to be 53%, lower than the results from the LIPs. DR ELCC was assessed by comparing its profile to a system calibrated to 1 outage in 10 years and calculated following the process below:

1. Using unscaled inputs, the LOLE was calculated

2. Net load was scaled up by 118% to achieve 1 outage in 10 years LOLE

3. The hourly DR profile was added in

4. 123 MW of load was added to each hour to achieve a 1-in-10 LOLE

5. The DR ELCC value was calculated by dividing the load added by the rated capacity

A challenge in using this method for calculating the ELCC value of DR resources was that the “rated capacity” was difficult to assess due to how DR resources rarely achieve maximum output, which is how a typical resource measures its rated capacity. Thus, SCE used the 95th percentile of DR load impact during LOLE. The other challenge was that DR and load shapes were strongly correlated with weather patterns. Ultimately, the SCE study team concluded that ELCC may be an appropriate measure of incremental contribution to reliability and as a means to compare the reliability contribution of different DR programs and to inform the LIP test results, but found that it may be an ineffective tool to forecast availability of DR load reduction and an estimate for load reduction value. Further research was explained as being needed on the definition of DR rated capacity, the relationship between modeled DR and load profiles, and whether marginal or average ELCC values should be used, before the DR ELCC could be used to calculate the QC of DR resources.

Issue 12 (Slow Response DR)

Per NERC standards and CAISO Tariff Section 40.3.1.1(1), the CAISO must secure the system within 30 minutes of a contingency, which leaves the CAISO with 10 minutes to assess system conditions and 20 minutes for resource dispatch and response. 

On June 20, 2018, SSWG participants reviewed and discussed draft report sections for each of the priority issues. The SSWG report discussed the “20-minute issue” for slow-response DR resources. On the one hand, the CAISO stated that DR resources can only qualify as Local RA resources if they have sufficient energy for frequent pre-contingency dispatch or be available within 20 minutes. On the other hand, DR stakeholders contended that many DR programs are dispatchable on a 30- or 40-minute basis, which has been historically counted for Local RA but would no longer qualify for Local RA under the CAISO’s proposal. The draft report highlighted that no solutions are presented at this time, as the CPUC takes time to complete a study on the pre-dispatch option, but the CAISO clarified that it will not conduct backstop procurement for Local RA capacity if slow-response DR resources are being relied upon for Local RA in certain areas. The results of a slow-response DR study were presented by the CAISO at a stakeholder meeting in October 2017.

On December 5, 2018, the CAISO presented its view on slow DR resources. To be eligible for local RA, the slow DR resource must be dispatchable in RTUC and its eligibility is subject to availability requirements. Resources that require a day-ahead notification of a binding dispatch will not be eligible for Local RA. The CAISO provides binding commitments but not binding dispatches in the day-ahead market. Pre-contingency dispatches beyond RTUC do not provide the CAISO enough flexibility to adjust resource output in response to changes between day-ahead and real-time runs. The CAISO added that slow RDRR cannot be dispatched pre-contingency for local reliability needs because it is only called upon once the CAISO declares a warning or emergency – thus it will not qualify for Local RA.

On January 24, 2019, the CAISO updated SSWG that it reconsidered the solution included in RA Enhancements Straw Proposal Part 1. Inputs that are required for day-ahead notification timelines are imprecise and use assumptions about operating conditions that are too far in advance that may result in unit dispatch that can cause inappropriate price impacts and inefficient outcomes. Rather, the CAISO preferred solutions that leverage real-time market timelines and take into account local load, import capability, and generator commitments to determine when to dispatch DR resources. Furthermore, the CAISO updated the SSWG on its consideration of availability-limited resources in the RA Enhancements Initiative, where the CAISO is moving toward hourly load forecasts to capture MWh energy needs, not just MW capacity needs in local areas.

On April 16, 2019, a SSWG meeting was held where CLECA presented on the need to give credit for DR resources for the load reduction it does provide within the CAISO required 20 minutes, even though it does not reach its full load reduction potential until 30 minutes. CLECA thus proposed that the CAISO measure the amount of DR response that occurs within 20 minutes, which would require some IOUs to reprogram meters to five-minute intervals and require the load impact protocols to include a 20-minute response amount in the report.

Issue 13 (Weather-Sensitive DR Qualifying Capacity)

On April 23, 2018, a SSWG meeting was held to continue discussions on identified high-priority issues. For weather-sensitive DR resources that have MW values vary by day and hour, the SSWG is considering how to properly count for such resources that may perform at a level higher or lower than its established qualifying capacity, creating reliability risks when over-counted and exposing resources to penalties when under-performing. Current rules require DR resources to either be in the market at their maximum capabilities or be fully replaced to avoid RAAIM penalties, so the SSWG is considering pathways for partial derating options on month-by-month basis. In the longer term, the SSWG discussed how the issue of establishing a more accurate qualifying capacity could be addressed through refinement of load impact protocols to include the impact of various temperatures on the performance of a weather-sensitive DR resource. This would require changes to the qualifying capacity counting methodology as well as changes to the bidding and replacement obligation for such resources. The DR parties are also pushing for similar exemption from RAAIM penalties of these resources as solar and wind resources, which are understood to vary based on weather conditions.

On June 20, 2018, SSWG participants reviewed and discussed draft report sections for each of the priority issues. Given that weather-sensitive DR resource capabilities vary by hour and day, the SSWG report discussed how their available MW capacity must also reflect that variability, which is not allowed under current RA rules that sets a fixed qualifying capacity number for all days and months of the year. This presents problems for weather-sensitive DR resources that face RAAIM penalties for bidding lower than the RA amount since the quantity of the hourly bid must minimally meet the quantity submitted in the supply plan. Note that the CAISO requested a RAAIM exemption for DRAM resources with FERC for 2018 and 2019. The SSWG report proposed a number of different solutions, including the ability to partially derate and replace capacity in the short term and development of revised qualifying capacity counting (similar to the construct for solar and wind resources) for weather-sensitive DR resources in the long term.

On July 17, 2018, a SSWG meeting was held that began with an introduction by the CPUC to the ELCC methodology and an overview by the CAISO on the variable energy resource (VER) forecasting and market participation model, followed by a presentation by PG&E on current DR Load Impact Protocols (LIPs). The key presentation was made by SCE on how the ELCC methodology could be applied to DR resources, which was observed to be not a simple “plug and play” because of factors like rated capacity and temperature sensitivity. However, SCE noted that LOLE is already being used as part of its A-Factor calculation in determining the incentive value for DR. While A-Factor accounts for program limits for the DR resource, it does not factor in the magnitude of load reduction. The A-factor represents the percentage of LOLE hours that can be captured by the DR program after taking into account program limits (i.e., program hours, duration limits, frequency limit). The A-factor for SCE’s Summer Discount Plan (SDP) resource is 98%. The ELCC value for a sample SCE DR resource was calculated to be 53%, lower than the results from the LIPs. DR ELCC was assessed by comparing its profile to a system calibrated to 1 outage in 10 years and calculated following the process below:

1. Using unscaled inputs, the LOLE was calculated

2. Net load was scaled up by 118% to achieve 1 outage in 10 years LOLE

3. The hourly DR profile was added in

4. 123 MW of load was added to each hour to achieve a 1-in-10 LOLE

5. The DR ELCC value was calculated by dividing the load added by the rated capacity

A challenge in using this method for calculating the ELCC value of DR resources was that the “rated capacity” was difficult to assess due to how DR resources rarely achieve maximum output, which is how a typical resource measures its rated capacity. Thus, SCE used the 95th percentile of DR load impact during LOLE. The other challenge was that DR and load shapes were strongly correlated with weather patterns. Ultimately, the SCE study team concluded that ELCC may be an appropriate measure of incremental contribution to reliability and as a means to compare the reliability contribution of different DR programs and to inform the LIP test results, but found that it may be an ineffective tool to forecast availability of DR load reduction and an estimate for load reduction value. Further research was explained as being needed on the definition of DR rated capacity, the relationship between modeled DR and load profiles, and whether marginal or average ELCC values should be used, before the DR ELCC could be used to calculate the QC of DR resources.

Separately, PG&E presented on a proposal to address the RAAIM for weather-sensitive DR resources, which face significant RAAIM penalties because the available capacity during any given hour and event day may not match the single QC value for the month, which is constant for all hours and weather conditions. As a solution, PG&E proposed that the expected MW of a resource for a given event be calculated using the estimated MW impact from the ex ante regression given the event window and the weather conditions. The coefficients and all other independent variables remain unchanged and enrollment is the same as what is used in the month-ahead showing. The RAAIM is then based on the expected MW given the event conditions and the delivered MW.

On September 25, 2018, a meeting was held to follow-up on potential ELCC solutions for weather-sensitive DR resources, including the data that are needed for the CPUC’s Energy Division to model ELCC and LIP comparisons. In addition, to support ex ante “reasonableness” of capacity from DR resources in the IOUs’ 60-day supply plans prior to the RA showing month, OhmConnect presented a proposal that would calculate the maximum reduction potential of customers within each IOU territory, similar to the NYISO’s Average Coincident Load (ACL) approach.

Issue 14 (DR & DRAM Resources in Year-Ahead RA Showing)

On April 23, 2018, a SSWG meeting was held to continue discussions on identified high-priority issues. The Joint DR Parties have raised the issue of how DR providers with a 2018 DRAM contract for deliveries in 2019 may not have all its customers under contract and registered with the CAISO by October 2018 for the LSEs to meet its year-ahead RA showing requirement. Under these rules, DR providers would already have to have customers in mind. Thus, the Joint DR Parties have proposed that the net qualifying capacity (NQC) of DRAM resources be equal to the contract quantity, rather than requiring that this capacity be registered in the CAISO DR Registration System (DRRS) by October for the LSE to meet its year-ahead showing.

On June 20, 2018, SSWG participants reviewed and discussed draft report sections for each of the priority issues. DRAM contracts are executed for one- or two-year periods, but given the adoption of a multi-year Local RA framework in the RA proceeding, DR stakeholders sought to develop multi-year DRAM contracts as well to provide DR providers with more market certainty and to allow IOUs to include DRAM resources in RA showings. A key issue stemmed from the IOUs requiring that DR providers have DRAM resources registered with the CAISO and have a Resource ID and NQC prior to October 1 of the previous compliance year in order to recognize DRAM resources in their year-ahead demonstrations for RA. As a result, the time to recruit and register customers for the DRAM would be truncated to August, or DR providers would have to have customers already in mind at the time of bid submission in the DRAM solicitations. Some of the proposed solutions include revising the requirement to sign customers under contract at the time that the DRAM contract is awarded and removing the requirement to obtain a Resource ID for the year-ahead compliance showing to allow the IOUs to count the NQC of resources procured. Specifically, DRAM resources without Resource IDs would be applied RA credit that would lower the RA obligations of other LSEs but would show DRAM resources as a supply-side resource for the month-ahead RA showing once customers and Resource IDs are obtained. This issue may need to await the CPUC’s evaluation of the DRAM pilots and determination on whether to make this a permanent supply-side DR mechanism.

Issue 20 (Export Limitations)

On December 5, 2018, Sunrun presented on the export limitation issue. While PDRs are not prohibited from exports, Sunrun discussed how exports do not count or are not compensated within the baseline methodology, which penalizes customers that offset load on days when not dispatched and do not provide credit for exported energy, thus reducing the capacity available to serve the market. Sunrun cited ISO-NE rules that enable DR resources within their Forward Capacity Market to export capacity from BTM resources interconnected under distribution utility tariffs. As a result, Sunrun proposes to modify the methodology such that DRsupply = - [G(t) - GLM], where G(t) is the metered generator output (MGO) and allows for net export values to be counted. This proposal maintains the customer penalty for dispatching during non-event days.

Integrated Distributed Energy Resources (R.14-10-003)

Background

On October 2, 2014, this proceeding was opened to consider the development and adoption of a regulatory framework to provide policy consistency for the direction and review of demand-side resource programs. The proceeding was originally called "Integrating Demand-Side Management" (IDSM) to optimize customer energy management solutions. Specifically, it aimed to: 1) create new goals for all demand-side resources in California; 2) refine cost-effectiveness methodologies; 3) re-assess utility marketing, education, and outreach efforts; and 4) review funding levels and sources. 

CESA supported D.15-09-022 that implemented AB 327 and expanded the definition to DERs from a sole focus on demand-side resources and utility programs. This rulemaking now focuses on creating a consistent end-to-end regulatory framework and developing compensation structures, tariffs, incentives, and other tools for procuring DERs.

On February 26, 2016, a Phase 1 Scoping Memo was issued that modified and broadened Phase 1 to include:

• Determination of how the DERs, needed to fill the required characteristics and the values (to be determined R.14-08-013), will be procured;

• Focus on the integration of DERs in a holistic way;

• Greater coordination with the work being performed in the DRP proceeding (R.14-08-013);

• Consideration of the adoption of localized incentives and the methodology used in determining the incentives; and

• Consideration of the role, business models, and financial incentives of utilities.

On February 12, 2018, an Amended Scoping Memo was issued that added two new issues to the scope of the proceeding: (1) design of alternative sourcing mechanisms or approaches that satisfy distribution planning objectives; and (2) consideration of how existing programs, incentives, and tariffs can be coordinated to maximize the locational benefits and minimize the costs of DERs. These added issues are positive for this proceeding as it will expand from the use of just competitive solicitation as a sourcing mechanism for DERs to provide grid services and may open the way for allowing DERs to meet shorter-term and smaller-magnitude deferral needs, such as voltage support. A number of questions related to the above two issues are included for stakeholder responses.

CESA expressed that competitive solicitations, which have been used thus far in the DRP and IDER pilots, may be well-suited for large MW needs, but that tariffs may be more appropriate to address more immediate short-term needs such as voltage support. With sourcing mechanisms for existing resources, the specified distribution grid needs may be met within a shorter timeframe, but would involve addressing the incrementality issue, which, in the IDER pilots, places existing resources under a “partially sourced” tranche. Further, tariffs may have the advantage of employing shorter contracts that can be adjusted as grid needs changed. CESA thus proposed the following alternative sourcing mechanisms: Volt/VAR Optimization (VVO) Tariff; Frequency Services Tariff; Hosting Capacity Tariff; Request for Bids; and Resiliency Program. In reply comments, CESA focused on rebutting IOU arguments on how competitive solicitations are the superior sourcing mechanism and should be the only focus of the IDER proceeding. Sunrun, CalSSA, SEIA, and EDF each proposed various innovative sourcing mechanism ideas as well, including an active hosting management mechanism and opt-in rates and tariffs, and similarly defended the merits of alternative sourcing mechanism.

See CESA's comments on March 29, 2018 and reply comments on April 13, 2018 on the Amended Scoping Memo.

There is a broader concern about the use of the LNBA values to set prices for these different distribution grid services, as the LNBA value is set based on avoided costs rather than for explicitly valuing energy and capacity or deferred equipment to meet a specific distribution grid need. The development of alternative sourcing mechanisms had major ties to the Phase 1 and 2 functions of the Smart Inverter Working Group (SIWG) implemented or in the process of being implemented for inverter-based generation. Rather than establishing these functions as costs, CESA aimed to pivot these functions to be viewed as services that should be compensated. Compensation, for example, for these functions could be based on the amount of solar generation curtailed and/or the deferral benefit of not having to upgrade distribution infrastructure.

Competitive Solicitation Framework Working Group (CSFWG)

On March 24, 2016, the ALJ issued a Ruling that established the Competitive Solicitation Framework Working Group (CSFWG) to develop a competitive solicitation framework and technology-neutral cost-effectiveness methodologies and protocols to be tested to address the reliability needs identified in R.14-08-013. Specifically, the CSFWG was tasked with the following:

• Define the services to be bought and sold within the areas identified in the analysis performed in the DRP proceeding

• Develop methodologies to count services provided and to ensure no duplication with procurement in other proceedings

• Develop solicitation rules or principles

• Develop solicitation oversight needs

• Develop solicitation evaluation method (i.e., least-cost, best-fit)

• Develop solicitation pro forma contracts (i.e., performance-based payment, pre-operational milestones, development security, performance assurance)

• Develop outreach plans to ensure robust participation in the framework (e.g., location, customer composition)

On March 28, 2016, a CPUC workshop was held to allow parties to discuss their prior solicitation experiences, lessons learned from these experiences, and bring into focus some general requirements for the CSFWG.

On August 1, 2016, the CSFWG published its final report identifying DER services that could be provided to the distribution grid. The CSFWG reached: full consensus on defining services to be procured; some consensus on principles, valuation, pro forma contract, and outreach; no consensus but clear recommendations on oversight; and neither consensus nor recommendations on double counting rules, incrementality, and rules/principles.

On December 22, 2016, D.16-12-036 approved the consensus recommendations from the Competitive Solicitation Framework Working Group’s (CSFWG) August 2016 report. The recommendations include:

• Definition of services to be procured using the framework (distribution capacity, voltage support, reliability back-tie, resiliency microgrid)

• Methodologies to ensure no double counting of services

• Development of rules and oversight

• Evaluation methods

• Pro forma contracts

• Solicitation outreach

The CSFWG developed five different counting methods for the CPUC to consider:

• Method 1 proposes that when a bidder provides offers, a pre-determined set of questions based on actual planning assumptions would guide the bidder's analysis of whether the offer is incremental or not.

• Method 2 recommends four factors for determining whether a DER is incremental: i) whether it is in a targeted category and funded through existing programs; ii) whether it is an existing program and/or technology and not innately incremental; iii) whether it is a new technology and not innately incremental; and iv) whether it addresses overloaded circuits or high node prices and is not innately incremental.

• Method 3 suggests assuming a pro rata baseline allocation of program effects across the grid and then assigning a DER value only to an incremental magnitude of contractually-committed DERs.

• Method 4 recommends a tranche analysis combined with a well-specified DER growth scenario, which includes three categories of DERs: i) those not already sourced through another channel; ii) those partially sourced through another channel; and iii) those wholly sourced through another channel.

• Method 5 suggests that when attributes of a DER have not been sourced through other mechanisms, they should be considered incremental, and if they have been sourced at least partially through another mechanism, at least a portion may be considered incremental if the bidder is able to demonstrate increased market participation due to the combined incentives.

Despite the lack of consensus on counting methodologies, D.16-12-036 allowed the IOUs to use any of the above methods in their pilot RFOs, required the IOUs to provide the planning assumptions for DERs in their solicitation packages, and adopted a set of principles in applying a counting methodology in the pilot RFOs:

• Ensure that ratepayers are not paying twice for the same service

• Ensure the reliability of a service

• Do not be unduly burdensome to participants

• Be technology-neutral, fair, and consistent

• Recognize that a DER is eligible to provide multiple incremental services and be compensated for each service

• Be flexible and transparent to bidders

The CSFWG agreed upon 12 principles that should apply to the Framework, which were also adopted by D.16-12-036:

1. Framework meets the identified need on a least-cost, best-fit basis

2. Framework utilizes a competitive process with broad markets

3. Framework is technology-neutral

4. Framework is as transparent as allowed within confidentiality boundaries

5. Framework identifies a need without prejudging the technology

6. Framework does not limit the amount of any one type of technology

7. Framework is a streamlined process

8. Framework is a fair and consistent process

9. Framework focuses on the identified need

10. Framework provides sufficient assurance of performance

11. Framework allows for flexibility in the number and type of bids

12. Framework includes a lessons-learned feedback loop

Finally, regarding market sensitive information, the decision cited D.06-06-006, which defines 'market sensitive' information as that which has the potential to materially affect an electricity buyer's market price for electricity and clarifies that such information must, at the very least, be contained in procurement plans or power purchase agreements, or related to these documents. For most data types that meet this definition, a three-year window for keeping such data confidential is adopted. 

On February 9, 2017, the charter for Distribution Planning Advisory Group (DPAG) was published. The DPAG is open to both market and non-market participants, one of which must be an Independent Professional Engineer (IPE) tasked with independently evaluating proposed electric distribution deferral pilot projects. The DPAG is advisory only and not a decision-making group that has approval authority, and is only created on an interim basis to test pilots while the CPUC awaits results from R.14-08-013. The DPAG will advise utilities on aspects of the distribution planning process related to identifying distribution deferral opportunities for the Regulatory Incentive Pilot, but the review of the solicitations will be done by the existing Procurement Review Group (PRG) to avoid conflicts with market participants. According to D.16-12-036, market participants are allowed in the DPAG to provide additional technical sophistication regarding DERs. The DPAG held six in-person meetings:

• March 16, 2017: Planning Process

• March 23, 2017: Evaluation Methodology

• March 30, 2017: Incrementality Metholodgy

• April 6, 2017: Project Selection

• April 13, 2017: Contingency Planning & Incrementality

• April 20, 2017: Wrap-up and Next Steps

On June 21, 2018, D.18-06-010 was issued that granted in part ORA’s petition for modification (PFM) of D.16-12-036 to prevent double cost recovery for both a previously authorized distribution capital project and a DER project that defers or replaces the distribution capital project. Specifically, this decision determined that utility spending for DER projects should be recovered initially through previously authorized distribution capital project spending from the utility’s general rate case.

Regulatory Incentives Mechanism Pilot

On April 5, 2016, Commissioner Florio introduced a draft Regulatory Incentives Proposal to address the need for considering utility incentives to deploy DERs. The purpose of this proposal is to test how an earnings opportunity affects DER sourcing behavior.

See CESA's comments on May 2, 2016 and reply comments on May 23, 2016 on the Draft Regulatory Incentives Proposal.

On June 13, 2016, a workshop was held to educate stakeholders on the ‘value engines’ of Commissioner Florio’s proposal.

On August 4, 2016, a workshop was held to discuss a range of proposals for a pilot implementation process to test the utility incentive mechanism for deployment of distributed energy resources. Parties discussed a step-by-step approach to deferral project identification, solicitation, CPUC authorization and approval, and cost recovery mechanisms. Among the key topics of discussion was the role and differences between the Distribution Planning Advisory Group (DPAG) and Procurement Review Group (PRG), and whether market participants can be involved in these review processes.

On September 1, 2016, Commissioner Florio drafted a revised proposal for a modestly-sized pilot that avoids the controversy of the “r-minus-k” concept. Instead, Commissioner Florio proposes a determination of incentives (similar to Efficiency Savings and Performance Incentive (ESPI) for energy efficiency) to incentivize DER deployment by utilities. The Revised Proposal sets the pre-tax incentive at 4% of DER investment (rather than as a percentage of avoided cost) without reliance on the value of 'r - k'. The IOUs are required to identify potential projects that have reasonable chance of being "cost-effective", which is defined as when the payment to the DER provider and the cost of the incentive is less than the avoided/deferred IOU capital investment. The DERs that are sourced also must be "incremental". To compare the impact of the pilot incentive, the IOUs are also required to have a control group.

Several concerns have been raised by parties regarding the proposed pilot, including the short timeline, project selection process, 'success' metrics, and mandate of minimum number of potential projects. In particular, SCE commented that there is limited value in all three IOUs piloting the same earnings mechanism, and instead recommended that the CPUC require testing of an alternative 'upfront payment' mechanism, whereby the utility would make a lump sum (ratebased) payment to the developer after the DER project or program is built out. SCE also proposed a mechanism where the IOU would earn a fixed percentage of the contract payment.

On December 22, 2016, D.16-12-036 approved the revised proposal for the Regulatory Incentive Mechanism Pilot and directed the IOUs to propose at least one and up to four projects testing the Regulatory Incentive Mechanism for distribution deferral purposes. By allowing for a requirement project and additional optional projects, D.16-12-036 stated that both the Competitive Solicitation Framework and the Regulatory Incentive Mechanism could be tested. If more than one project is proposed, then the CPUC directed the IOUs to have one of the optional projects mirror the Demo C project in R.14-08-013, which allows the Demo C project to serve as a 'control group'. If the solicitation is deemed successful, the IOU would be authorized to record the value of the incentive in a balancing account for recovery in the subsequent General Rate Case (GRC), when the IOUs' past distribution capital spending will be reviewed to ensure no duplication of recovery of the deferred traditional distribution investment. Once the deferral period ends and a traditional investment is made, no incentive would be recovered for that year and going forward. Provisions of the Regulatory Incentive Mechanism include the following:

• Sets a 4% pre-tax incentive when applied to the annual payment for the DER alternative for the deferred traditional infrastructure investment

• Establishes a Distribution Planning Advisory Group (DPAG) for each IOU to review and provide feedback on potential projects and allows market participants to participate in the DPAG process

• Establishes an Independent Professional Engineer (IPE) to support the DPAG in evaluating the merits of distribution projects identified by an IOU for deferral or displacement

• Requires the development of a contingency plan in consultation with the DPAG

• Requires the development of transparent bid evaluation methodologies to be included in solicitation packages, but protects the confidentiality of market-sensitive materials such as the avoided cost of the deferred traditional investment

• Sets a 6-month timeline for utilities to identify at least two pilot projects for an initial distribution deferral RFO

• Requires a Tier 3 Advice Letter filing that proposes to procure a DER solution for the identified problem

• Any previously-authorized distribution capital spending will not be reviewed until the next GRC to allow utilities to retain any savings from deploying less costly DERs

• Directs DPAG discussions on the development of a technology-neutral pro forma contract after solicitations have taken place

In response to SCE's alternative incentive mechanisms, D.16-12-036 opted to not adopt them because it would require further clarification and would present too many variables to allow the CPUC to properly evaluate the outcomes of the Regulatory Incentive Pilot. 

On February 20, 2017, the DPAG for the IDER Incentive Pilot was established.

On June 29, 2017, an Order was issued on June 29 denying the Application for Rehearing of D.16-12-036 for the CPUC looking to the DRP OIR to inform its decision-making process. This was in response to a January 23, 2017 Sierra Club challenge of D.16-12-036 alleging that it violated Section 769 by allowing natural-gas-fueled (or fossil-fueled) DERs to participate in the Regulatory Incentive Pilot. The CPUC relied on the definition of DERs in the DRP OIR, which included allowing natural-gas-fueled DERs.

On July 10, 2017, a workshop was held to answer questions from stakeholders on the IOUs’ advice letters filed in accordance with D.16-12-036. Each of the IOUs are instructed to propose two pilot projects to: (1) evaluate the viability of conducting an expedited solicitation process as embodied within the adopted recommendations of the Competitive Solicitation Framework Working Group (CSFWG); and (2) evaluate to what extent a 4% pre-tax incentive to the annual DER payments encourages the IOUs to pursue the procurement of DER solutions instead of traditional infrastructure projects. A key unaddressed issue in the pilot design is the lack of consensus on incrementality and double-counting methodologies. CESA submitted responses to the advice letters in support of the pilots but with comments on specific issues that should be addressed to provide greater clarity and market certainty to DER solution providers:

• The double counting methodology used by the IOUs must clearly define what types of DER resources are wholly or partially incremental.

• Exporting energy storage should be allowed to participate.

• DER alternatives should be more strongly considered in contingency planning.

• Project timing criterion for selecting eligible projects does not reflect the procurement and deployment timeline of all DERs, especially existing projects.

See CESA's responses to the advice letters of SCE, SDG&E, and PG&E on July 14, 2017.

On December 19, 2017, Resolution E-4889 approved the IDER pilot solicitations of SCE and SDG&E and adopted the following:

• Adopted SCE’s hybrid Method 4+5 and SDG&E’s Method 4 for determining incrementality and assessing DER attributes.

• Approved SCE’s contingency planning process.

• Required distribution planning information be made available in RFO documents to help bidders determine residual need and determine incrementality of their bids.

• Required IOU explanation for rationale of each security request and amount in pro forma documents.

• Ensured that IOUs do not categorically exclude or prohibit BTM solutions from exporting to grid.

• Determined that 2019 is not a reasonable timeline for DER procurement.

• Determined that provisions in interconnection agreements address the rights and obligations of utilities and developers regarding interconnection and transmission obligations.

• Approved the disclosure of customer data “as much as possible” to inform offers and support bidders, except when there are issues around customer privacy and confidentiality.

• Adopted the submission of M&V plan with revenue-grade metering, but allows for flexibility for alternative M&V methodologies by bidders.

• Required SDG&E to set its distribution capacity requirements to reflect the peak time need in a given year, not to add additional requirements (e.g., year-round availability).

• Required SDG&E to set a day-ahead dispatch requirement for DERs.

Overall, the Resolution was largely positive for CESA members. While not specific, the Resolution made important clarifications regarding the incrementality of services, rather than basing this determination on resources (i.e., services offered by existing DERs that are above and beyond what is expected under other programs should be considered “incremental”). Importantly, the CPUC agreed with many of the comments made by CESA and member companies on the Draft Resolution to improve the pilot solicitations. The CPUC adopted the recommendation by CESA/Sunrun to direct revisions to SDG&E’s contingency planning process that requires the IOU to find replacement resources rather than placing cure provisions on DER providers, thus aligning with the contingency planning process proposed by SCE. The CPUC found it unreasonable especially since SDG&E is seeking only one counterparty in their RFO. In addition, the CPUC adopted the recommendation by CESA/Sunrun to change to a day-ahead dispatch to provide time for DERs to respond to a utility signal. Finally, the CPUC agreed with CESA and Tesla that site control should not be an eligibility criterion but instead an evaluation criterion in the pilot solicitations .

See CESA's comments on November 20, 2017 on the Draft Resolution E-4889.

On April 30, 2018, a PD was issued that modified D.16-12-036 to have the costs of IDER pilot projects where DERs avoid or defer a distribution capital project previously authorized or pending be recovered through previously authorized distribution capital project spending from the IOUs’ GRC. On November 9, 2017, ORA filed a Petition for Modification (PFM) of D.16-12-036 because of duplicative requests to relieve distribution system constraints in previous GRC filings and again in IDER pilot advice letters. The PD agreed with ORA that double recovery of authorized funds could occur if an IOU uses the funds allocated to the previously-authorized distribution capital project during the course of the GRC years and records spending in the balancing account for the IDER project during the same years. Overall, this looks like a “clean-up” issue that will ensure that no double recovery occurs for the same distribution need. Comments were filed by ORA in support of the PD and by the IOUs against the PD, citing how the CPUC practice is to allow approved GRC funds to be repurposed and reallocated to other pressing investment needs if the original need no longer exists.

DER Action Plan

On September 29, 2016, CPUC President Picker published a draft DER Action Plan that aims to provide the CPUC’s long-term vision for California’s DER future, which can be achieved by rates and tariffs, distribution grid infrastructure and planning, and wholesale market integration. In addition, the DER Action Plan is intended to identify continuing efforts and further near-term actions needed to support the long-term vision.

On October 18, 2016, a workshop on CPUC President Picker’s draft DER Action Plan was held to discuss the long-term framework and roadmap for DER adoption and answer questions from stakeholders. The CPUC staff clarified that this document is intended to provide guidance for Scoping Memos in new proceedings and identify issues that do not yet have a procedural home. It is supposed to function similarly to the Energy Action Plan.

To implement the DER Action Plan, the CPUC intends to establish a Steering Committee consisting of CPUC staff (no explicit public stakeholder role) to identify opportunities for coordination and sequencing of various DER-related proceedings, avoid bottlenecks, and address other process issues. CPUC Commissioners will be briefed periodically similar to how it is done with the Safety Action Plan.

SCE 2018 GRC - Distribution System Operator White Paper

In its 2018 GRC Application, SCE highlighted "integrating DERs" as a new strategic objective not discussed in previous GRCs. A white paper was published along with the GRC Application that discusses SCE’s need to gradually transition to locational and market-based pricing and to build a "next generation electric grid". SCE discussed the need for advanced sensors, communications, and automation to expand their capabilities as Distribution System Operators (DSOs).

SCE also proposed several unique ideas on their views of the DSO’s role:

• Provide dynamic DER adoption and performance forecasts

• Provide seamless DER interconnection for customers

• Aggregate customer DERs or coordinate with third-party aggregators to optimize DER usage between wholesale market products, distribution grid needs, and individual customer preferences

• Provide price certainty to individual DER owners

• Administer local DR or energy storage programs to shift load in specific grid locations, as opposed to broad service-territory-wide programs

• Identify projects for distribution load growth deferral

While this 'vision' paper for the future role of SCE as a DSO is encouraging, SCE emphasizes the need for grid modernization investments, DER performance validation, and DER market design development before the DSO role is realized.

Avoided Cost Calculator & Cost-Effectiveness Frameworks

Background

In February 1983, the Standard Practice Manual (SPM) was published to provide formal guidelines on assessing the cost-effectiveness of distributed energy resource (DER) programs, such as energy efficiency (EE) and demand response (DR). The SPM has been revised multiple times, with the latest update in October 2001, but it does not specify how the test results are displayed or the level at which cost-effectiveness should be assessed. The costs and benefits components are assessed from different perspective:

• Ratepayer Impact Measure (RIM) Test: This test measures what happens to rates due to changes in utility revenues and operating costs caused by the program (i.e., expected change in customer rates). The benefits are the avoided costs of supplying electricity, and the costs are the program costs for creating and administering the program, the incentives paid to participants, and decreased revenues from decreased retail sales. A benefit-cost ratio above 1.0 indicates the program likely results in lower rates over the lifetime of the program or equipment.

• Program Administrator Cost (PAC) Test: This test looks at resource costs from the program administrator perspective (e.g., utility), where the benefits are the avoided costs of supplying electricity and the costs are the administrator's incurred costs, incentives paid to the customer, and sometimes the increased supply costs when load increases. A benefit-cost ratio above 1.0 indicates net benefits to the administrator.

• Total Resource Cost (TRC) Test: For the combined utility and participant perspective, this test measures costs and benefits for the resource option, with the benefits measured in avoided costs of supplying electricity and the costs measured in program costs to the utility and the participant costs, including installed equipment costs. A benefit-cost ratio above 1.0 indicates that the program is beneficial on a total resource cost basis to utilities, participants, and ratepayers.

• Societal Cost Test (SCT): This test is a variation of the TRC but with the societal perspective, where total costs are quantified as a whole to society as opposed to just the utility and ratepayers. As compared to the TRC, a higher marginal cost and a societal discount rate may be used, tax credits may be omitted, interest payments may be considered a transfer payment instead of an expenditure, and externality costs related to generation may be used. Use of a societal discount rate places a higher value on the impacts of programs on future generations. The GHG adder estimates the value of the reduced carbon emissions that DERs provide, in addition to the value of GHG carbon allowance permits that utilities are required to purchase.

The CPUC has historically used the RIM, PAC, and TRC for budgetary-related decision-making, while using the SCT for evaluation purposes only. As reference, the Regulatory Assistance Project (RAP) published a literature review of cost-effectiveness tests. 

D.05-04-024 was issued to adopt the Avoided Cost Calculator (ACC) to measure energy efficiency (EE) cost-effectiveness. The assumptions, data, and models used in the ACC require periodic updates to stay current with market conditions, prices, and trends. D.10-12-024 was then issued to modify and adopt the ACC for use by demand response (DR) programs, which was further detailed in the DR Cost-Effectiveness Protocols. 

In 2014, the IDER proceeding (R.14-10-003) was opened to, among other things, establish a unified cost-effectiveness framework that would apply to all DER programs, technologies, and proceedings. D.16-06-007 found that the ACC is used in determining the cost-effectiveness of resources across many CPUC proceedings and that it is reasonable to require that all CPUC proceedings focused on the approval, evaluation, or cost-effectiveness evaluation for other purposes of a DER use the most recent version of the adopted ACC. D.16-06-007 required that a single avoided cost model applies to all DER proceedings and that the ACC be updated annually by May 1 of each year.

Avoided Cost Calculator (ACC) Update

On February 9, 2017, a Ruling was issued seeking comment on a Staff Proposal recommending a SCT to evaluate DERs that could be used alongside the traditional TRC and PAC tests or modified versions of those tests. Specifically, the Staff Proposal recommends:

• Adoption of a SCT for consistent use across all DER proceedings

• Adoption of specific methods to calculate a social discount rate, an air quality value, and a GHG adder;

• Adoption of one or more options for incorporating the GHG adder into SPM tests

• Adoption of a new avoided GHG emissions co-benefits input to the DER cost-effectiveness framework for certain technologies

On April 3, 2017, a Ruling was issued that introduced a Staff Proposal for an interim GHG adder to be used as an input into a proposed SCT or modified TRC/PAC tests. A GHG adder estimates the value of the reduced carbon emissions that DERs provide and is proposed to be based on the marginal cost of abatement to achieve the state’s GHG goals (as opposed to being based on the value of GHG allowances as it is currently in the DER cost-effectiveness framework), according to the Staff Proposal. This marginal cost of abatement is in addition to the cap-and-trade price and does not reflect the renewable energy contracts already in place. An annualized approach that applies a straight-line escalation from $0/tonne-CO2 in 2017 to $250/tonne-CO2 in 20230 is recommended by Energy Division based on its preliminary modeling results from the IRP proceeding (R.16-02-007), instead of using preliminary year-over-year values. Staff also asserts that this approach more adequately reflects the value of DERs over the long term and incorporates the lead time to develop and gradual ramp-up of DER programs and investments. The first instance in which a GHG adder may be used would be in the energy efficiency potential study being undertaken in R.13-11-005, which will inform future energy efficiency goals. The IRP process will not develop a GHG adder value until after the EE goals update, and this timing mismatch is likely have a disruptive effect on EE potential, goals, budgets and programs – if GHG goals are ignored, EE budgets are likely to suffer large cuts, and based on current cost-effectiveness restrictions. Staff discussed how additional experience using the SCT is necessary. 

On August 8, 2017, a workshop was to allow parties to ask questions and provide clarity on the Societal Cost Test Staff Proposal. The workshop discussed specific aspects of the Staff Proposal, including the social discount rate, air quality benefits assessment, use of 'damage cost' versus marginal GHG abatement cost as the permanent GHG adder, and incorporation of the GHG adder in the SPM tests. The components of the Staff Proposal include an interim GHG adder to reflect the value of decreased GHG emissions, an air quality adder to reflect the healthcare costs associated with air pollution, and a 3% societal discount rate to reflect the value to future generations of environmental protection. Generally, CEDMC supported the use of a full SCT to measure DERs, with a priority toward energy efficiency as the least-cost investment. TURN cautioned against arbitrarily inflating DER values given that the ACC operates on the assumption that DERs only replace fossil generation. Finally, the IOUs supported the use of marginal abatement costs from the IRP proceeding, use of the market-based cap-and-trade ceiling prices, and use of the weighted average cost of capital as the societal discount rate.

On August 11, 2017, D.17-08-022 was issued that granted a one-year waiver to the Avoided Cost Calculator. The CPUC found this reasonable given the ongoing processing delays in obtaining technical consultants to provide the update.

On August 31, 2017, D.17-08-022 was issued that adopted a series of values based upon the ARB Cap-and-Trade Allowance Price Containment Reserve (APCR) Price as an interim GHG gas adder value for use in the Avoided Cost Calculator when analyzing the cost-effectiveness of DERs and will replace any existing GHG value currently in the Avoided Cost Calculator. The APCR Price is defined as the highest cost of compliance with the cap-and-trade requirements, but is not equated with a marginal carbon abatement price at this time. In 2015 dollars, the interim GHG adder thus increases linearly from $56.51 in 2015 to $85.27 in 2030. The perceived urgency for adopting an interim GHG adder comes from the need to inform inputs into the Energy Efficiency Potential Study and EE goals to be adopted in September 2017. Development of a permanent GHG adder will be considered in the future, in coordination with the IRP proceeding and, if and when adopted, will replace the interim GHG adder adopted here. No parties opposed the adoption of the adder on an interim basis. To limit the risk of overvaluing resources, the PD proposes to adopt a sunset date of May 1, 2018 for the interim adder with the option to extend once for up to one year.

On March 14, 2018, a Ruling was issued that included an amended staff proposal for comment, building off the original staff proposal from February 2017 that recommended inclusion of an air quality value, a social discount rate, and a greenhouse gas adder to estimate the value of the reduced carbon emissions that DERs provide. D.17-08-022 also adopted an interim GHG adder value for use in the avoided cost calculator based on the Cap-and-Trade Allowance Price Containment Reserve Price. One of the focuses of this proceeding is to develop technology-neutral cost-effectiveness methods and protocols to support a preferred approach to bid evaluation within the competitive solicitation framework. The amended staff proposal makes several key changes and refinements that would apply the modified tests to be used for all DER activities:

• Adopt the modified TRC and PAC tests as replacements for the existing TRC and PAC tests since this was implictly adopted with the adoption of the interim GHG adders

• Adopt a modified RIM test that is modified in the same manner as the TRC and PAC tests

• Adopt the SCT as an additional test to be used initially for information purposes only but allow each resource proceeding to determine how (if at all) to use the test, though use of the SCT requires "additional experience"

• Consider and determine the avoided cost of carbon abatement (GHG adder in TRC/PAC tests) in R.16-02-007 and then adjust the value to avoid inaccuracies (e.g., exclusion of cap-and-trade carbon allowance selling price, RPS costs, and alignment of similar dollar years between IRP and ACC)

• Adopt the high impact value (i.e., avoided social cost of carbon based on damage costs resulting from climate change) as developed by the Interagency Working Group on Social Cost of Greenhouse Gases as the social cost of carbon (GHG adder in SCT)

• Adopt a 3% discount rate for the SCT, which is lower than the current rate and thus gives more weight to the interests of future generations

• Use the EPA’s Co-Benefits Risk Assessment Health Impacts Screening and Mapping Tool (COBRA Tool) to compute and adopt an Interim Air Quality Adder until a more robust model can be developed

The CPUC staff is also authorized to continue to study and analyze improvements to the DER cost-effectiveness framework, including the development of a common resource valuation method. Importantly, staff explained that the information gained from using the SCT can provide more information to the CPUC and stakeholders on the environmental impacts of programs and resources, including for the IRP proceeding, so all DER cost-effectiveness analysis should be required to include the SCT for informational purposes at this time for the next three years. 

CEDMC, Joint Environmental Parties, and SEIA fully supported adoption of the modified TRC and PAC with the GHG adder values adopted in D.18-02-018.37 However, IEPA, PAO, TURN and the IOUs disagreed because either further review and consideration was needed in R.16-02-007, the GHG adder values adopted in D.18-02-018 do not represent a reasonable estimate of avoided abatement costs, or the values adopted in D.18-02-018 do not reflect dynamic incorporation of demand-side measures in the IRP model.

For the SCT, PAO and the IOUs supported information-only use of this test, while supporting the use of the TRC and PAC for assessing cost-effectiveness and for approving program budgets, procurement decisions, and tariffs. Otherwise, if the SCT is adopted for more than that, the IOUs are concerned about potential over-procurement of and bias toward DERs as opposed to other more cost-effective, utility-scale resources. SEIA and Sierra Club, however, disagreed and warned that, by not adopting the SCT, environmental benefits are being valued at zero and the Legislative intent would not be fulfilled. 

For the air quality adder, most parties generally agreed, but the IOUs contended that the CPUC should explore more accurate models (e.g., USEPA BenMap model) and the IOUs and PAO generally called for more workshops, including with ARB staff. More granular geographic data and mapping of DERs with local emissions levels may be needed. SEIA, however, contended that the COBRA model may be underestimating air quality impacts. 

For the societal discount rate, the IOUs and TURN opposed its use as the weighted average cost of capital as the SCT should evaluate the costs and benefits of a DER over the expected life of that resource, not to evaluate tradeoffs between generations. The CPUC staff explained that capital is productive and can be invested elsewhere, and so there is an opportunity cost. 

On July 13, 2018, Resolution E-4942 was issued that updated the Avoided Cost Calculator with the new GHG adder, given that D.18-02-018 from the IRP proceeding adopting a GHG adder for use in cost-effectiveness of DERs. Notably, it rejected the IOUs’ recommendations to adopt the IRP GHG Planning Price instead of the proposed GHG adder and to adopt marginal emissions rates developed as part of the SGIP evaluation, which the IOUs aregued as being more accurate. The CPUC did not want to re-litigate issues or overhaul established methodologies for cost-effectiveness. The CPUC also adopted nine data updates from the E3 report on ACC updates to reflect market conditions, trends, and prices, including natural gas prices, electricity forward prices, ancillary service costs, hourly market price shapes, cap-and-trade allowance price forecasts, T&D hourly allocation factors, generation capacity hourly allocation factors, and natural gas generation costs and performance. 

On March 25, 2019, a PD was issued that established and defined a universal cost-effectiveness framework and policies for DERs for all resource-specific proceedings, with a modified TRC test being used as the cost-effectiveness test for all DER-related applications or advice letters submitted on July 1, 2019 and thereafter. The TRC test was determined to be the broadest range of perspectives, including the utility and participant costs and benefits, and was determined to have similar values as the IRP modeling - thus, it was adopted as the primary test. In addition to the modified TRC test, PAC and RIM tests are also considered to have value and was thus adopted to inform proceedings. The IOUs discussed how the PAC gives focus on least-cost procurement under utility regulation while the RIM is the only test that provides information on rate impacts. The PD noted that, while GHG abatement costs may not be embedded in rates, the costs of programs to reduce GHG emissions are included in the RIM test. Importantly, the PD affirmed a previous decision to replace the interim GHG adder value with the GHG adder values adopted in D.18-02-018.

The PD found that there was no evidence at this time to support adoption of the SCT as the primary cost-effectiveness test, but the SCT will be tested across the three elements (avoided social cost of carbon plus high impact and average values of “damage costs”, interim air quality adder of $6/MWh, and societal discount factor) for planning purposes in the IRP proceeding through December 31, 2020 to determine whether and to which extent that the SCT can be used to achieve carbon reduction objectives. The PD also reasoned that this testing will support the evolution toward a smoother transition toward the Common Resource Valuation Method that consistently measures societal benefits, including the economic value of programs. Rather than determining which test to use in individual proceedings, the PD clarified that the CPUC is intent on determining these societal values for not just DERs but all resource types in the IRP, which is the appropriate venue to address this as opposed to a piece-meal decision-making approach. During 2021, CPUC staff is instructed to evaluate the elements of the SCT and recommend to the CPUC whether the SCT should be continued as implemented in this decision or revised pursuant to evaluation results. A workshop shall be held before the end of 2019 to allow for stakeholder comments on the evaluation, which should be finalized and published by mid-2021.

Finally, the PD clarified the process for changes to the ACC, where “minor” changes would go through the Resolution process in even-numbered years beginning in 2020 whereas “major” changes (e.g., modeling methodology, category changes, data input lists) would require a formal process that begins in even-numbered years but conclude in odd-numbered years.

Cost-effectiveness tests are important to supporting the approval of program budgets and tariffs, which impacts programs/tariffs like NEM, utility DR programs. Depending on the test, a different “perspective” is taken in assessing the benefits and costs of a program - e.g., program administrator (utility), participant, ratepayer, or societal. The TRC test was found in the PD to more comprehensively captures the benefits and costs of resources and was modified to capture GHG adders from the IRP. Most of CESA’s policy work do not involve too much program cost-effectiveness evaluations. Upon assessing the PD, CESA found it reasonable for the CPUC to only apply the SCT on an information-only basis until further review and analysis is conducted in the IRP proceeding, which is working toward developing a common resource valuation methodology. CESA fully supports DER growth but found the PD strikes the right balance of gaining more information, deferring appropriately to the IRP, and leveraging a modified TRC approach in the interim that should still benefit DERs. CESA decided to not file comments for the following reasons:  

• CESA agreed with the PD that there are significant uncertainty and more analysis needed with the SCT, which is not yet widely used elsewhere for cost-effectiveness analysis. For example, it is unclear on how air quality impacts can be attributed to a DER with locational and time granularity based on current tools assessed to date. It would not be reasonable to adopt this "adder" at this time. In the IRP, we are still trying to better understand the locational impact of criteria pollutants, for example, based on changes in dispatch of a fossil generator from the resources procured in the IRP. At the same time, without individual unit dispatch modeling in the IRP, this may persistently be difficult to quantify and attribute.

• CESA agreed with the PD that these societal benefits should be measured in the IRP as these benefits are not just attributed to DERs and their associated programs/tariffs but also to all other resources. In other words, IFOM storage would likely generate similar types of societal benefits by being dispatched to obviate the retention or operation of gas generators. By applying the SCT to only DERs, then it may create an unfair bias in resource procurement toward DERs. It thus seems more appropriate to have the IRP proceeding measure and calculate societal benefits for all resources.

• CESA found the PD still supports DERs in cost-effectiveness assessments through the adoption of IRP GHG adders in a modified TRC test. In D.18-02-018 (see p. 116-118), the CPUC adopted a higher GHG adder using a straight-line method as compared to the overall GHG Planning Price to be used in the LSEs' IRP plans to provide more certainty to DER providers and because DERs were not optimized within RESOLVE. The use of two GHG prices in general was a concern raised by CESA in the IRP PD prior to D.18-12-018, but we recognize the lack of DER optimization in RESOLVE. At the same time, it looks like RESOLVE will have very limited optimization of DERs for the 2019-20 cycle as well, so that is an uncertainty going forward.

• SGIP appears to be unaffected by this PD. SGIP last had a cost-effectiveness study conducted by technology in 2015, and an updated study is expected later this year. However, upon further review of the SGIP methodology, it appears that this program takes its own unique cost-effectiveness testing approach (TRC, STRC, PCT, PAC) for assessing energy storage cost-effectiveness that factors into account market transformation objectives. Storage did not fare well in the 2015 assessment but CESA believes that it may have more to do with how storage operations are applied within the tests as opposed to which test is applied in themselves. For example, the studies may not have accurately captured the time-differentiated charge-discharge operations when assessing avoided costs. Thus, while the PD may appear to touch upon how SGIP may apply cost-effectiveness tests, CESA understands that SGIP is differentiated and unaffected by this PD given the market transformation objective of the program. This may change later depending on if SB 700 implementation changes the objectives of the program.

In comments, the IOUs and ratepayer advocates (PAO, TURN) supported the PD’s recognition of the IRP role in establishing values for use in cost-effectiveness tests and in developing a common resource valuation methodology for all resources (not just DERs) – i.e., SCT should not be developed just for DERs. However, in order to do so in the IRP, they recommended the need to optimize DERs in the IRP models. The IOUs also sought to modify the PD to clarify that the TRC should not be used for the cost-effectiveness assessment of the NEM tariff (where the RIM test is appropriate), utility procurement (where least-cost, best-fit criteria is used), or transportation electrification applications (where its own methodology is being developed in the DRIVE OIR). Finally, the IOUs pushed to have the GHG adder from the IRP to be made equal for supply-side and demand-side resources and disputed the use of the air quality adder or methane leakage impacts due to the lack of evidence, particularly with the use of a $/MWh metric since reduction of all MWh at all locations is not equal in terms of air quality impacts.

Meanwhile, the DER and environmental community expressed major disappointment with the PD. CEDMC noted that the TRC fails to recognize customer DER investments as a benefit and to incorporate non-energy benefits (e.g., home comfort, resale value, health impacts) in line with policy objectives. To account for multiple perspectives, CEDMC recommended weighting cost-effectiveness assessments by one-third using the SCT and by two-thirds using the PAC. Many commented on the need to use the SCT, which has a track record in other states and is required by statute (i.e., Public Utilities Code Section 701.1(c) and 400(b)), but recommended that the SCT also incorporate additional benefits (e.g., locational benefits, avoided transmission costs, smart inverter benefits). SEIA and CALSSA recommended that the air quality adder use $15.30/MWh from the COBRA model since they do not include health impacts from particulate matter (as opposed to $6/MWh in PD, does not consider water conservation or methane leakage). Finally, since the IRP only considers supply-side resources, they expressed concern with a focus on determining SCT-derived values in the IRP. In general, all parties seemed to agree on the need for the CPUC to expeditiously develop a CRVM methodology.

On May 21, 2019, D.19-05-019 was issued that approved the PD with modifications to clarify that the formal ACC update process would commence in August 2019 for completion in 2020 and to note an exception for the TRC as primary DER cost-effectiveness test where directed by statute or CPUC decision. The decision also added commentary that SCT is used in other programs and states but is used inconsistently or disparately. As such, the decision stood by its determination that it would be premature to adopt the SCT as one of the primary methods without further research on the SCT and its individual elements.

On August 2, 2019, Resolution E-5014 was issued that proposed 11 data updates, four corrections, and one minor update:

• Eliminate the high-efficiency heat rate threshold when the implied heat rate is lower than 6,900 BTM/kWh to reflect the growth of renewables and higher-efficiency natural gas units on the margin and to more accurately reflect marginal GHG emissions

• Update natural gas prices, electricity forward prices, hourly market price shapes, and natural gas avoided costs from various data sources

• Update ancillary service costs to 0.9% for annual energy from CAISO 2018 Annual Report on Market Issues and Performance

• Update CO2 market price forecast from 2019 IEPR Mid-Demand forecast

• Adopt GHG adder values from IRP’s D.18-02-018 with adjustments

• Update marginal T&D costs from IOUs’ recent GRC filings

• Update T&D hourly allocation factors based on 2018 recorded weather

• Update financing costs for new generation from CEC’s 2019 Estimated Cost of New Utility-Scale Generation in California: 2018 Update report

In response to comments, the Final Resolution rejected many of PG&E’s and SCE’s proposals to allow negative hourly energy values, include longer-term weather forecasting techniques for allocation of avoided T&D costs, remove “extreme days” when natural gas prices exceed $15 in the model, and exclude the grid-related portion of distribution capacity costs and use the 2019 IEPR forecast for natural gas avoided costs.

On August 30, 2019, an ACC update workshop was held to discuss potential major changes to be implemented in 2020, including the following:

• Changing the marginal generation unit, currently a natural gas generator, to reflect the changing grid

• Adopting different values for flexible, local and generic generation capacity

• Aligning the ACC with the IRP

• Adding additional avoided costs (e.g., grid services provided by smart inverters)

• Adopting a new estimation method for GHG emissions that does not use hourly implied marginal heat rates

• Considering how to align DER cost-effectiveness, which no longer uses a Resource Balance Year (RBY), with other non-RBY valuation methods (e.g., least-cost best-fit)

• Determining whether the gas escalation rates used to determine avoided energy prices shapes are accurate

• Incorporating renewable integration costs

For unspecified avoided distribution costs, the CPUC staff proposed to use the IOUs’ GNA filings (which E3 will calculate by Fall 2019), specifically the more certain feeder level data, but SEIA noted the limitations of using the GNA that only looks five years out (when DERs last more than 20 years) and recommended hour-by-hour granularity and marginal distribution capacity costs used in ratemaking beyond five years. PG&E and SCE supported the CPUC staff proposal since the GNA uses post-load-transfer data but requested that specified distribution deferral values be excluded from use in planning use cases, such as the IRP models and ACC, to avoid double counting of DERs. SDG&E, however, took the strongest view in opposing the use of unspecified distribution deferral values unless such values can be developed with locational granularity, leading to an over- or under-valuing of DERs.

For unspecified avoided transmission costs, SEIA made the case for calculating these values given the evidence of canceled transmission projects from the CAISO’s Transmission Planning Process (TPP). However, the IOUs argued that CAISO transmission costs are fungible with generation capacity costs, so DERs should not be counted as avoiding both; SEIA countered that the two are not perfect substitutes except in certain local areas. SEIA also commented on how DERs can affect RPS-related transmission costs, but the IOUs responded that such costs are already incorporated in IRP modeling. The CAISO and others clarified SEIA’s understanding by highlighting how this targeted review in PG&E local areas reflected circumstances changing over a number of years (e.g., economic recession, federal lighting standards), not just recently-occurring changes (i.e., DER growth).  Specifically, the CAISO highlighted how certain DERs reduce load in the middle of the day, but net load peak demand decreases was attributable to gross load decreases. The large time lag in transmission investments also makes it hard to attributed avoided transmission costs to DERs, according to the CAISO. Instead, the CAISO expressed how avoided transmission costs are project, location, and need specific. The IOUs also echoed the view that avoided transmission costs should be specific to non-wires alternatives (e.g., energy storage) deferring discrete transmission projects.

The CPUC staff also proposed to keep “naturally-occurring” DERs in the counterfactual analysis, but several parties highlighted the challenges of determining what is “natural”. SCE and PAO recommended that non-targeted DER growth be split into two components: policy driven versus naturally occurring or code driven.

On October 7, 2019 and October 21, 2019, opening and rebuttal testimonies were submitted. The IOUs, CUE, and CalWEA coalesced around the need to align avoided costs with the IRP, which shows that the long-term marginal resource is solar and battery storage, not gas-fired resources. In other words, it is no longer appropriate to use the cost of new entry for a combustion turbine in the ACC to calculate avoided capacity costs minus the revenues it would accrue from the energy and ancillary service markets. The IOUs proposed a methodology to allow for comparability with supply-side resources by using the IRP outputs for assumed buildout to produce resource output shapes and a Resource Balance Year (RBY) approach – i.e., the future year when there is a forecasted need for new generation. While E3 proposed to use a GHG adder for DERs only, the IOUs said that this would result in unequal treatment.

By contrast, SEIA and Vote Solar proposed to include several additional benefits attributable to DERs, including resiliency, avoided fuel price volatility, and market price reduction effects. Specifically, SEIA and Vote Solar proposed to freeze the actual market heat rate shapes for the most recent calendar year. While avoided T&D costs are being considered in the DRP proceeding, SEIA and Vote Solar made the case for why unspecified T&D investments can be avoided by DERs and thus should be incorporated in the ACC. According to CPUC staff, it takes many MW of DERs to avoid a single MW of T&D investments.

CLECA, however, expressed concerns with using battery storage as the marginal resource in these calculations due to concerns of energy limitations, not being a generation source, and operational limitations due to ITC considerations. CLECA added that the current ACC method should use a combustion turbine in avoided cost calculations for capacity that is needed for contingency capacity, which cannot be calculated using RESOLVE. The RBY was also identified as unworkable for resources with quick installation and development times.

On November 15, 2019, a Ruling was issued that clarified that the CPUC did not intend for avoided T&D costs to be limited to discussion in the DRP proceeding, as the IDER proceeding is positioned to determined how adopted T&D values are incorporated in the ACC. A Ruling and Revised Staff Proposal was subsequently issued that provided information on the methods and models to align the ACC avoided cost inputs with the IRP modeling outputs. Since the IRP RESOLVE modeling results will not be prepared until early October, the ALJ indicated that the staff proposal should be expected thereafter.

On November 20, 2019, a Ruling was issued on that included a modified Staff Proposal that would align the data, models, and methods used for DER cost-effectiveness with those used in the IRP process. The Staff Proposal recommends adoption of a new avoided cost that estimates the value of high global warming potential gases, such as methane and refrigerants. This new avoided cost estimates the value of reduced methane leakage from reductions in natural gas use and the value of increases or decreases in refrigerant leakage that can result from installation of heat pumps or changes in refrigerant types.

On December 17, 2019, parties filed comments and briefs. In them, the IOUs emphasized the need to align avoided cost outputs and assumptions with that of the IRP proceeding, including ensuring that demand- and supply-side GHG prices are consistent. In their view, avoided T&D costs should be addressed in the CPUC’s DRP proceeding and the CAISO’s TPP initiative. The IOUs, meanwhile, disagreed with the Staff Proposal to include a value for mitigating high global warming potential gasses in the ACC, which are not IOU specific costs incurred and are instead social costs that should be addressed through specific DER programs or other CPUC-approved mechanisms, such as the SCT. Resiliency and avoided fuel price volatility were also opposed as not being evident costs on the IOUs.

On March 13, 2020, a PD was issued that proposed to adopt a number of major changes to the 2020 ACC. In comments to the PD, DER and environmental groups were generally supportive of the PD except for the adoption of a zero or minimal value for unspecified avoided transmission costs. SEIA and Vote Solar disputed the PD’s characterization of their proposal since their NERA regression analysis only accounted for load-driven transmission investments that DERs could actually avoid while removing “policy driven” transmission investments to access renewable energy zones. Either long-run marginal distribution costs or the transmission access charge (TAC) could be used as a proxy for avoided transmission. Clean Coalition argued that there is some value as evidenced by the TAC ($20/MWh) that would be avoided through DERs, and that some value is needed to assess additional DERs versus transmission investments when it comes to supporting microgrids and resiliency. Meanwhile, CEDMC made a broader point about how the CPUC should consider participant investments as non-energy benefits, not a cost like ratepayer spending in the TRC and SCT.

Like the DER parties, the IOUs, CUE, and CalWEA found several technical problems but found the PD would systematically overestimate DER value. First, the straight-line extrapolation of GHG adder costs through 2030 would not put demand- and supply-side on equal footing to identify least-cost GHG reduction measures. Instead, the IOUs recommended a constant percentage rate of increase from the 2020 cap-and-trade price to the 2030 GHG price. Second, the IOUs disagreed with the inclusion of high GWP gases because these emissions categories are not included in IOU compliance obligations, therefore does not constitute a utility cost that can be avoided. Rather, they should be considered in the SCT (e.g., out-of-state methane leakage) or in the appropriate resource-specific proceedings (e.g., refrigerants for heat pump water heaters). Third, the IOUs took issue with the PD would overestimate capacity costs because they are not tied to when storage is needed for reliability, while CLECA disputed storage as being the marginal capacity resource altogether because four-hour storage cannot meet a six-hour LOLE outage, as identified in SERVM. The IOUs and PAO advocated for the resource balance year (RBY) concept to capture how storage is selected in the IRP to avoid GHG emissions, not to be selected as the most economic reliability solution (i.e., not count them for avoided generation capacity) – though DER parties opposed the RBY due to the lumpiness of capital investments. Finally, the IOUs explained that the “No New DER” scenario fails to account for naturally-occurring DERs and mandated DERs (e.g., Title 24 PV), thereby mixing their resulting benefits.

On April 24, 2020, D.20-04-010 was issued that adopted the Staff Proposal for the 2020 update to align the Avoided Cost Calculator (ACC) more closely with the IRP and DRP processes to support consistency in evaluating supply and demand side resources for electric sector planning.

• Avoided GHG emissions: A “straight-line” GHG adder through 2030 under the “No New DER” IRP scenario is adopted in order to evaluate DERs as candidate resources along with supply-side resources, while post-2030 GHG values from the IRP RESOLVE modeling will be considered in the future. To capture fuel substitution effects, the decision also adapted the GHG adder to captures the difference in hourly marginal emissions and annual emissions intensity.

• Avoided generation capacity: The decision determined to measure the avoided capacity cost of all DERs using the first avoided unit of supply-side resources under the “No New DER” scenario. The cost of new entry (CONE) of a four-hour battery storage is adopted as the proxy marginal new-build resource capacity addition in all years.

• Avoided high global warming potential (GWP) gases: For programs that reduce BTM natural gas consumption or involve refrigerants, a new avoided high GWP gas category is added to the ACC. For resources that reduce the upstream need for natural gas, the decision approved a new avoided cost of the leakage of gases with high GWP gases such as methane, reflected in a higher GHG adder.

• Avoided fuel volatility: The decision declined to adopt avoided fuel volatility for inclusion in the ACC because such benefits are “highly speculative” and DERs have not been demonstrated to provide hedging value.

• Unspecified avoided distribution costs: The decision acknowledged that some portion of unanticipated grid needs could be satisfied by DERs and adopts a system-average approach (Staff Proposal Method 1) based on Grid Needs Assessment (GNA) data.

• Unspecified avoided transmission costs: The decision did not adopt avoided transmission costs for SCE and SDG&E but maintains the current method for calculating avoided transmission cost for PG&E because the SEIA/VS proposal does not account for transmission costs that cannot be avoided. Staff is directed to refine the avoided transmission method and consider Local RA values as well.

• Avoided resiliency costs: The decision rejected the incorporation of avoided resiliency costs as an issue that should be addressed in the Microgrids proceeding (R.19-09-009).

Given the lack of completed calculations, this presented some concern that the details in the methodology may not have enough time for stakeholder review. Furthermore, whether the GNA and DDOR reports cover the full range of distribution investments for which IOUs seek cost recovery for has not been vetted through a staff gap analysis. It is also odd to see discrepancies in avoided values, where DERs in SCE and SDG&E territory would be valued at zero for avoided transmission costs while having a minimal though non-zero avoided transmission cost value for DERs in PG&E territory.

On June 30, 2020, Resolution E-5077 was issued that adopted the specific avoided cost factors, sources, and calculation methodologies that would produce the ACC values.

The updates to the ACC implemented a previous decision with greater detail on sources, methodologies, etc. Specifically, the following major changes were adopted:

• Generation Capacity Avoided Cost: Previously, the ACC estimated the avoided cost of generation capacity using a natural gas combustion turbine as a proxy, with the annual capacity values allocated to each hour of the year for 30 years, using E3’s RECAP model. The results of the RESOLVE model show that a battery storage resource better represents the marginal capacity unit. To create greater alignment with IRP, the generation capacity value will now use a new four-hour battery storage resource as a proxy, with their fixed costs being used to calculate the annual levelized fixed cost of a battery over its expected useful life. The revenue that batteries earn from the energy and ancillary markets will be based on SERVM production cost modeling, and subtracted from the leveled fixed costs to calculate a Net CONE in $/kW-yr.

• Energy Avoided Cost: Previously, the avoided cost of energy was forecasted using energy futures and gas turbine modeling. The average energy cost in the short run was based on the last 22 trading day average on-peak and off-peak market prices forecasts for NP-15 and SP-15. For the long run, energy costs were forecasted using last available futures market price and long-run energy market price. The avoided cost of energy will be now be determined by hourly values from the SERVM model, based on the No New DER case. Because SERVM models the dispatch of all generators, it produces more accurate values for future energy prices than the previous methodology.

• Ancillary Services Avoided Cost: Previously, the avoided cost of ancillary services was forecasted as a percentage of wholesale energy costs. Estimates of hourly avoided ancillary services costs, will come from SERVM production cost modeling, using data from the No New DER case. Because the SERVM model simulates the dispatch of electric resources, it is a more accurate indicator of actual ancillary services prices than the previous method.

• Avoided GHG Cost: Previously, GHG impacts were based only on hourly marginal emissions and calculated using an implied heat rate incorporating market price forecasts for electricity and natural gas. This approach does not reflect the need to reflect declines in GHG intensity to reach the GHG goals. The short-run impact of DERs decreasing a utility’s cap-and-trade obligation is calculated in the various resource cost-effectiveness tools by multiplying the hourly marginal electric grid emissions (in tonnes/kWh) by the change in load in kWh. However, in the long-run, changes in load will result in changes in a utility’s planning and procurement that must be rebalanced to achieve GHG goals. The 2020 ACC uses a combination of hourly marginal emissions and resource portfolio rebalancing to more accurately project hourly GHG emissions over time, estimated using SERVM production simulation modeling. The energy sector GHG avoided cost reflects the marginal cost of GHG abatement based on GHG shadow prices modeled in RESOLVE. The GHG adder is the difference between the GHG avoided cost and the cap and trade allowance price forecast.

• Distribution & Transmission Avoided Costs: Previously, the ACC used the marginal transmission and distribution capacity costs from utilities’ GRC Phase Two proceedings for the avoided cost of distribution and transmission, as a combined value. Unspecified distribution deferral avoided costs will be calculated using a system-average approach, using a counterfactual forecast to determine the impact of DERs on load. The ACC will extrapolate the avoided cost estimates from the Distribution Deferral Opportunity Report and the Grid Needs Assessment, as filed in the DRP proceeding. As PG&E is the only utility to file transmission-level costs in their GRC, transmission values for SCE and SDG&E will be modeled using PG&E’s method and data specific to each utility.

• Avoided High GWP Gases: Previously, the ACC did not include avoided costs associated with high GWP gases. The ACC will include a new avoided cost associated with leakage of refrigerants and methane, including three components. The impacts of methane leakage will be estimated by increasing avoided GHG emissions for all DERs, using an upstream in-state methane leakage adder. This new avoided cost also includes an additional BTM adder, which will increase the avoided GHG emissions only for those programs that eliminate natural gas appliances from residential buildings. The upstream in-state methane leakage adder has been determined to be 5.57%, and the BTM adder is 3.78%, based on CARB data.

In comments on the Draft Resolution, SEIA and Vote Solar made specific recommendations to modify the GHG adder to align with the IRP and the avoided transmission costs to $30/kW-year for PG&E and $22/kW-year for SDG&E based on the use of transmission peak capacity allocation factors (PCAFs). The significant GHG impacts of out-of-state methane leakage associated with natural gas burned in California should be considered as a societal benefit when DER programs are evaluated. TURN and SoCalGas, on the other hand, expressed concern with the inclusion of the avoided cost of natural gas leakage since the future of the gas distribution system is still speculative and because it is inappropriate to assume there will be any reduction in reported methane leakage on the system from a single DER project. CLECA, on the other hand, focused on the battery storage assumptions used to set the marginal generation capacity, arguing that the projections are too aggressive, O&M costs miss certain cost factors, and energy market revenues are too high given the lack of perfect foresight. Finally, the IOUs offered recommendations on specific fixes to make more realistic the assumed heat rates, energy prices, regulation prices, and load adjustments to reflect Title 24 requirements and energy efficiency goals. They also made an overarching comment that the finalization process should be delayed to allow for additional SERVM modeling.

DER Tariff Sourcing Mechanisms

Background

On August 13-14, 2018, a workshop was held to discuss streamlining of the current DIDF as well as non-RFO sourcing mechanisms, such as tariffs and standard offer contracts. One of the objectives of this workshop was to ensure that stakeholders were on the same page with respect to the scoping issues, definitions (e.g., "what is a tariff?"), and directives and to ensure coordination of current IDER activities to maximize locational benefits and minimize costs.

The first day focused on how the CSF could be streamlined. Facilitated by the ALJ, participants took a step-by-step consideration of the timeline in the process and brainstormed specific measures that could be taken to streamline the time it takes for any given step. Some of the ideas discussed was bundled procurement processes, pre-approval of eligible developers, and pre-approval for the IOUs to conduct competitive solicitations as long as the proposed project fell below a certain threshold (e.g., cost, MW). Regarding the pre-approved developer list, the workshop participants identified that this list may not save significant time in this process, but if such a list is to be developed, it may include developer experience, credit background, commercial viability of technology, ability to meet online date, and customer eligibility.

The second day focused on ideas for alternative non-RFO sourcing mechanisms, such as targeted programs, incentive programs, and tariffs. The obligations, rules, prices, and standardized contracts for tariffs were discussed, in addition to considering whether different sourcing mechanisms and/or services were better suited for individual customers or aggregators to reduce transaction cost and performance risk. The IOUs echoed their previous positions that competitive solicitations are more effective than tariffs, especially when applying determining incrementality and mitigating the risks of over-procurement (i.e., leading to overpayment) and under-procurement (i.e., creating potential safety and reliability concerns. However, there was also an appetite to develop targeted DER tariffs that build on existing programs and focus on specific services, even from a learning perspective. Key elements needed in tariffs were identified as eligibility requirements, specific service definition, locational requirements, cost-effectiveness, price signals, penalty provisions, operational controls, telemetry, interconnection, and performance validation. Questions were raised about incrementality concepts as it applies to tariff-based sourcing of grid services. 

On November 16, 2018, a Ruling was issued that directed parties to file proposals for DER tariffs by February 15, 2019, which will be followed by a workshop to discuss them. Proposals are required to be responsive to the following guiding principles:

• Does not inherently favor traditional infrastructure investments over distributed energy resources or vice versa

• Does not inherently favor any specific distributed energy resource type

• Provides an incentive for energy usage and market behavior (consuming, buying, and selling energy and capacity and derivative products) that is reasonable expected to reduce greenhouse gas emissions and other air pollutants

• Provides an incentive for energy usage and market behavior (consuming, buying, and selling energy and capacity and derivative products) that is reasonably expected to minimize overall energy system costs, relative to other available options, including, but not limited to: distribution costs, transmission costs, generation costs, and other costs that may overlap with the above categories, including costs associated with vegetation management, preventative de-energization, insurance, and any other related costs

• Enables utilities to recover all CPUC-approved revenue requirements equitably from both participating and non-participating customers

• Is reasonably expected to improve the deployment of cost-effective distributed energy resources relative to the other mechanisms currently available

Partnership Pilot

On February 12, 2021, D.21-02-006 was issued that adopted the Staff Proposal on a five-year DER tariff pilot (dubbed the Partnership Pilot) with some modifications to test a new sourcing mechanism for DERs to avoid or defer distribution investments. First, the decision made some revisions to the guiding principles included in the Staff Proposal to inform the development of the DER tariff:

• Provide a payment to DER customers for distribution deferral resources, where the total costs to execute and maintain the DER deferral tariff reduces overall energy system costs, relative to other available options: This principle was maintained from the Staff Proposal.

• Result in a level playing field for DERs in comparison to traditional infrastructure investments, while also achieving technology neutrality across all DERs: This principle reflects a consolidation of principles related to technology neutrality between DERs and wires and also among DER types without the need to call out every DER type. How some DERs may be better suited to meet certain needs than others are a “fact” rather than a principle To not conflict with this principle in regards to DERs versus wires, the decision eliminated the principle to reduce GHG emissions.

• Enable IOUs to recover all CPUC-approved revenue requirements equitably and transparently from both participating and non-participating customers: This principle was largely maintained from the Staff Proposal, with minor modifications to emphasize transparency.

• Improve the deployment and utilization of cost-effective DERs for distribution deferral purposes, relative to other mechanisms currently available, to maximize savings to ratepayers while also encouraging innovation of DERs: This principle reflects a consolidation of the cost-effectiveness, energy usage, and “learn by doing” principles, with an added element of encouraging innovation.

• Leverage private investment in DERs, including existing DERs participating in other CPUC programs not already providing deferral services, to achieve distribution deferral benefits of least marginal cost to ratepayers: Instead of calling out specific programs, this principle was consolidated to affirm that the tariff is a payment for services and thus not subject to a holistic cost-effectiveness assessment for the DER, contrary to CUE’s suggestion.

• Ensure payments to DER customers for distribution deferral are incremental and total no more than the deferral value cost cap: In affirming the tariff as a payment for services, this revised principle guarded against double payments, as warned by SDG&E in their comments.

Furthermore, the decision rejected very specific principles proposed by PG&E and deemed them to not be principles (e.g., not paying for unneeded services, verification, penalties, etc.). With these principles in mind, the decision proposed to adopt the Partnership Pilot, renamed from staff’s proposed Clean Energy Customer Incentive (CECI) Pilot, with certain key modifications to the various elements, as outlined below. At a high level, the Partnership Pilot is structured to offer uniform simplified terms and payments for enrollment in a tariff to be dispatched according to project-specific needs. The IOUs would be required to propose at least one Tier 1 opportunity and two Tier 2/3 opportunities to pilot this DER tariff.

• Prescreening: The decision maintained the Staff Proposal’s prescreening requirement and process and affirmed its value to shorten the offer evaluation period, reduce recurring submittal requirements, and confirm minimum provider viability. As such, prescreening is required to participate and be listed in marketing materials and the IOUs are directed to submit their prescreening criteria that should reflect technology neutrality and not inhibit new market entrants. Starting on July 15 of every year and lasting 30 days, prescreening applications can be submitted, with approval in this process being active for two years (i.e., reapplication required thereafter). Applicants will not bear the cost of prescreening during the pilot period.

• Subscription period: The decision maintained the Staff Proposal. The IOU will solicit offers during a subscription period, which will close when enough offers are accepted to meet the grid need, plus a 20% procurement margin or by the date determined by the IOU for contingency plan implementation (if insufficient capacity is subscribed). The procurement margin reasonably protects against DER project attrition or under-performance and can be reevaluated in the future. The contingency plan date will be specified at subscription period launch. The specific procurement goal will be established for a 12-month period in line with the Staff Proposal – i.e., enough MW and MWh to defer the grid need for at least one year. Off-ramps will be in place after Year 3 to evaluate whether to continue with annual subscription windows.

• Offer reservation and acceptance: The decision did not make modifications to the Staff Proposal, pointing to 90% acceptance trigger as a starting point to evaluate DER interest in the tariff and then determining whether it could be increased or decreased. At the same time, the decision recognized that year-by-year and project-specific factors could justify lower acceptance triggers. Upon submitting an affidavit of interest from the host customer, providers can file for an offer reservation. The affidavit was affirmed as being necessary to guard against queue hogging and phantom projects. The IOU will execute contracts with providers once 90% of deferral need is subscribed (i.e., acceptance trigger).

• Pricing methods: The decision generally affirmed the Staff Proposal without modification. The tariff budget is project-specific and will be set at 85% of the cost cap of a planned investment. The cost cap, and thus the tariff budget, will be finalized by November 15 as a one-way adjustment to allow for budgets to increase as costs or grid needs increase but not allow for budgets to decrease, all in an effort to provide market certainty to customers.

• Payment structure: The decision refined and consolidated Staff Proposal’s multiple tiers of payments. An upfront payment (20% of cost cap) will be provided upon installation and commitment to dispatch (via contract signing upon hitting acceptance trigger), but unlike the Staff Proposal, the decision clarified that customers must disclose their participation in other programs (e.g., SGIP, NEM) and not be eligible for the deployment payment tier. Reservation payment (30% of cost cap) will be provided as a capacity payment during the specified timeframe, and performance payments (50% of cost cap) will done to compensate actual dispatch according to contracted criteria. Notably, the test payment tier was eliminated since this is a prerequisite for the DIDF RFO and would simplify the payment structure.

• Marketing and outreach: Considering aggregators do not have access to individual customer information, the IOU will serve as a marketing partner to approved service aggregators but not directly market any of the aggregators. To create a level playing field, the decision directed the IOUs to inform customers of available tariffs and programs on a dedicated webpage by April 30 to advertise the pilot and list the contact information of approved aggregators, with the ability for customers to opt into being contacted by eligible aggregators.

• Incrementality: The decision adopted the Staff Proposal’s incrementality clarifications and disagreed with IOU-specific approaches or with awaiting SGIP or NEM reforms. Projects receiving SGIP funding should be considered fully incremental for the purposes of DIDF RFO bids and deferral tariff offers, if the provider commits to meeting the dispatch requirements pursuant to the contract for the IOU-solicited deferral services. Projects already compensated through NEM should be considered fully incremental for the purposes of DIDF RFO bids and deferral tariff offers, if the DER provider makes a material enhancement to provide the IOU-solicited deferral services (e.g., the addition of storage that commits to meeting the dispatch requirements described in the solicitation terms and pursuant to the contract for the IOU-solicited deferral services).

• DERMS requirement: Despite consideration of a potential DERMS requirement in the Staff Proposal, the decision found no evidence of DERMS deployment and integration being required as a precondition of participation in the pilot.

Importantly, in contrast to current RFO procurement where DERs must be solicited and contracted for the entire grid need at the RFO stage to proceed with deferral, ratable procurement is proposed for this pilot that would allow the incremental needs to be met over time. The decision explained that its proposed levels for procurement margin and acceptance trigger as guarding against over- and under-procurement risks.

Relative to the PD, the decision was revised to acknowledge some of the design details of the annual procurement goal, as raised by SCE but required the IOUs to address some of these detailed matters in their GNA/DDOR filings, including number of procurement goals or tranches, length of each tranche, payment amounts and levels for each tranche, etc. DPAG feedback shall inform IOU November 15 advice letter filings requesting approval to launch subscription periods, thus giving parties like CESA an opportunity to review, shape, and protest/respond to the program details.

See CESA's comments on January 25, 2021 and reply comments on February 1, 2021 on the Proposed Decision

CESA supported many aspects of the Partnership Pilot, including the market certainty provided by the one-way adjustment to the cost cap, the use of acceptance triggers applied to the annual procurement goals to take advantage of ratable procurement approaches, the affirmation and clarification on incrementality policies, among others. While largely supportive and greatly appreciative of the CPUC’s leadership on the Partnership Program, CESA offered the following recommendations:

• The Revised Guiding Principles should be adopted with revisions to align with the current project-specific scope of the DIDF.

• Ratable procurement should be implemented through annual acceptance triggers and rolling subscription periods.

• Continuous subscriptions with minimal pauses between subscription periods improve customer experience and increase the odds of meeting the full deferral need.

• The reservation and performance payment tiers should be consolidated into a single reservation payment tier to reflect the nature of distribution grid needs and to ensure technology neutrality with wires investments.

• The prescreening criteria and application process should be centralized to apply to all utilities rather than potentially subjecting providers to duplicative processes for each utility.

Many DER providers and DER trade associations, as well as SCE, were broadly supportive of the pilots. Notably, SCE pointed to a potential significant challenge of per-kW incentives for deployment and capacity fluctuating based on customer enrollment or kW increase for any given year. Instead, SCE proposed an alternative budget framework that would smooth out the incentives to give each new customer access to the same per-kW deployment incentive, regardless of year, calculated by taking the totals across the deferral period instead of annualizing them. CUE, on the other hand, repeated many of the same arguments against ratable procurement, cost cap publication, and simple price payment as creating risks to ratepayers. Each of the IOUs also proposed revising the acceptance trigger from 90% to 100% to ensure reliability is maintained and provide certainty in the contingency planning process and sought two-way revision of the cost cap in the event of estimated cost changes.

Standard Offer Contract (SOC) Pilot

On February 12, 2021, D.21-02-006 was issued that adopted the Staff Proposal on a three-year SOC pilot with some modifications to test a new sourcing mechanism for DERs only to avoid or defer distribution investments, with at least one Tier 1 opportunity selected for this purpose. Utilizing the technology-neutral pro forma (TNPF) contract in this pilot, the IOUs would be directed to release cost caps for deferral projects, followed by submission of pricing sheets under simple auction pricing by interested providers during the subscription period. Since the tariff pilot is adopted for BTM resources, the SOC pilot is limited to IFOM resources, though it could be expanded to all resources in the future. A review of the pilot’s success will occur in Year 3. Like with the tariff, all bidders will be required to go through prescreening. Relative to the PD, the decision was revised to remove the prerequisite for developers to participate in prescreening processes, agreeing with SCE that its current process for bidder screening is already robust and successful.

CESA supported the SOC pilot, which will likely require the consideration of some implementation details, but they can be addressed in the DPAG process. Most parties were supportive or did not comment on this proposal. SCE only recommended that prescreening processes be eliminated, being unnecessary for a proven sourcing mechanism.

See CESA's comments on January 25, 2021 on the Proposed Decision

DER Tariff Proposals

CESA submitted a proposal that provided our recommendations for the design principles for any DER tariff proposals. CESA focused our proposal around a new distribution and hosting capacity tariff proposal to leverage existing processes but we also proposed concepts for voltage support and resiliency tariffs. The latter two ideas are less fully developed as there are still unresolved issues beforehand.

See CESA's proposal  submitted on February 15, 2019 on the Ruling

On March 4-5, 2019, a workshop was held to further vet and discuss the range of proposals where some were innovative, some that had similarities to the DIDF RFOs, and one that seemed a bit out of scope.  Key themes that arose in the workshop revolved around issues of incrementality, assuring IOUs that tariffs can deliver for their needs, and concerns of providing upfront payments for the deployment of DERs when the need hasn’t been met yet (i.e., overprocurement risk).

On April 15, 2019, a Ruling was issued directing post-workshop responses to questions relating to DER tariff proposals, which included the following:

• The Distribution & Hosting Capacity Tariff (CESA) proposal would synergize with the DIDF in creating a tariff that supplements RFOs with ratable procurement that addresses longer-term investments via capacity and performance-based energy payments. Any residual distribution capacity needs could be addressed through an RFO structure.

• The Grid Services Tariff (CALSSA) proposal would establish a pre-determined compensation rate at 85% of the annualized cost of the traditional infrastructure investment for the operational requirements, in-service deadlines, payment terms, and penalties for the distribution service. The tariff would be offered for a minimum 10-year term.

• The DIDF Tariff (PG&E) ­is a standard-offer contract with terms and conditions for distribution capacity for a short subscription period (e.g., a few days) where sellers would submit a pricing sheet at different percentage levels of the deferral value (e.g., 50%, 75%, 90%) and PG&E would select the cheapest options. Deferral would not be pursued if tariff does not procure sufficient DER solutions.

• The Simplified Standard-Offer Contract (SCE) proposal is offered via a reverse auction mechanism on a limited and non-negotiable subscription basis in the targeted deferral location for distribution capacity, with availability made similar to the ReMAT Program. DER providers would indicate the quantity of services they are willing to provide at prices. The capacity contribution of each DER type would be determined by technology effectiveness factors for each hour of the grid need. Prices would adjust across one or more subscription periods but would stay below the deferral value of the project.

• The Riders Tariff (SCE) proposal would provide additional incentives on top of existing programs and/or tariffs at specific locations and times. These would include an upfront program-based incentive and/or an ongoing tariff-based incentive to encourage the use of these DERs to provide distribution capacity and energy to defer a need by at least one year. Tariff subscription would be open for one year, but payments could be withheld until the IOU has assurance that there is sufficient participation to meet the grid needs. The compensation methodology should consider whether the DER is already being compensated for distribution value under the existing program or tariff.

• A Regional Distributed Energy Resources Tariff (SEIA & Vote Solar) based on the difference between marginal distribution costs by division or by planning area and the system average marginal cost for each IOU would establish an hourly pricing tariff for DERs to provide long-term distribution benefits while leveraging existing DER programs (e.g., CSI, SGIP) so long as the DER is new. This tariff would not be tied to specific and near-term needs identified in the DIDF but it could be coincident to such needs. Payment would be made on the calculated $/kW-year over a period of time.

• The Bring Your Own Device (Sunrun) proposal is a retail-side program that enables customer participation similar to DR programs and offers a range of products, including distribution capacity, peaking capacity, and negative market peaking capacity. A Tier 1 bill credit or upfront payment would commit DERs while a Tier 2 performance payment would be made for performance-based dispatch, which summed together would be less than the deferral value of the traditional asset.

Within the context of these proposals, the ALJ was seeking feedback to further vet each of the proposed tariffs listed above, including whether parties like CESA would support/oppose or modify any of the proposals. Ultimately, there is an opportunity for one or some of these tariff ideas to be piloted in the next DIDF cycle. CESA was supportive of the consideration of various DER tariff proposal ideas, including ours, but we expressed some broader issues that need to be addressed before the CPUC considers adopting any tariff idea. In particular, CESA’s proposal was intended to address challenges with the lack of time provided for the market to respond to the DIDF RFOs (e.g., 1-3 months), which makes tariffs an appealing sourcing mechanism for developers to be granted additional time and some certainty to acquire customers and/or develop projects in response to an identified grid need. CESA also recommended the following general points:

• The CPUC should revise the design principles and incorporate some of our suggested modifications.

• Over-procurement risks should be mitigated but the CPUC should not strive to eliminate these risks when assessing the proposed tariffs.

• Without further clarity or refinement of incrementality from the CPUC, it is difficult to assess whether proposed tariffs adequately address incrementality.

Additionally, CESA provided our responses to each of the posed questions. CESA supported the adoption of a DER tariff given the advantages that it can provide as opposed to just relying on an RFO approach for distribution deferral needs. Multiple pilots could be conducted, but the CPUC should focus on a shortlist of tariff ideas. While the near-term focus could be on piloting a DER tariff tied to the DIDF, a broader consideration of DER tariffs should be made for general tariffs that are not tied to specific distribution projects. In terms of other parties proposals, CESA supported the proposals of CALSSA, Sunrun, and SCE (Rider Tariff) with some modifications and clarifications. Of course, CESA indicated its top preference for piloting our modified DHC Tariff, which include the following elements:

• The DHC Tariff would procure for distribution capacity and hosting capacity services.

• The DHC Tariff would establish performance obligations and penalties similar to what is established for RFO contracts.

• Distribution capacity projects with steady and moderate load growth would be targeted for the DHC Tariff combined with an RFO.

• The subscription period for the DHC Tariff would be open for a minimum one-year period.

• A cap on subscription levels should be set for the DHC Tariff.

• An upfront and pre-determined incentive payment price should be set in the DHC Tariff along with ongoing $/kWh performance-based incentive payments.

In sum, CESA's modified proposal takes a ratable procurement approach to push out Year 3 distribution capacity needs out further to allow for the longer subscription period and for more time in the RFO solicitation and deployment process. Finally, CESA ranked low PG&E's and SCE's Standard-Offer Tariff proposals and SEIA/VS's Regional DER Tariff proposal. The former is too similar to the DIDF RFO and would not provide material learnings in a pilot, while SEIA/VS's proposal is out of scope in the near term but should be considered in the long term.

At a high level, the comments were split between “developer friendly” and “utility friendly” positions, with SCE taking positions favoring both sides. All parties were generally in agreement that any tariff idea should be piloted first, though there was disagreement on which tariff proposals to pilot and whether there should be more than one pilot. Other than SCE, the other IOUs and CUE believed that there were fundamental flaws related to grid reliability and safety and over-payment for each of the non-IOU proposals. PG&E’s comments were notable in that they have shifted to a strong anti-DER stance, aligning it closer to SDG&E and differentiating significantly from SCE. In response, CESA focused on the bigger picture of why and what types of tariffs are needed. CESA recommended that the CPUC select tariff proposal ideas that are refined to address various issues and risks but are also materially different from the current competitive solicitation sourcing mechanism, given that tariff proposals that would generate new insights are worth piloting. In other words, the IOUs’ standard-offer contracts are not worth piloting because they represent only a slight variation of the current RFO process. CESA also sought to respond to the arguments by the IOUs and CUE to dismiss many of the tariff proposal ideas because of flaws that they identified. Since no tariff proposal is complete and requires refinement, CESA supported SCE’s suggestion to use a working group process to work through tariff challenges and risk factors.

See CESA’s response on May 24, 2019 and reply comments on June 7, 2019 on the Ruling

IDER Tech Neutral Pro Forma (TNPF) Contract

Background

On March 24, 2016, the ALJ issued a Ruling that established the Competitive Solicitation Framework Working Group (CSFWG) to develop a competitive solicitation framework and technology-neutral cost-effectiveness methodologies and protocols to be tested to address the reliability needs identified in R.14-08-013. Specifically, the CSFWG was tasked with the following:

• Define the services to be bought and sold within the areas identified in the analysis performed in the DRP proceeding

• Develop methodologies to count services provided and to ensure no duplication with procurement in other proceedings

• Develop solicitation rules or principles

• Develop solicitation oversight needs

• Develop solicitation evaluation method (i.e., least-cost, best-fit)

• Develop solicitation pro forma contracts (i.e., performance-based payment, pre-operational milestones, development security, performance assurance)

• Develop outreach plans to ensure robust participation in the framework (e.g., location, customer composition)

On December 22, 2016, D.16-12-036 approved the consensus recommendations from the Competitive Solicitation Framework Working Group’s (CSFWG) August 2016 report. The recommendations include:

• Definition of services to be procured using the framework (distribution capacity, voltage support, reliability back-tie, resiliency microgrid)

• Methodologies to ensure no double counting of services

• Development of rules and oversight

• Evaluation methods

• Pro forma contracts

• Solicitation outreach

Working Group Implementation

On June 4, 2018, the IOUs reconvened this working group to begin discussions on the development of a technology-neutral pro forma contract. In the August 1, 2016 final report, the working group highlighted the need and process for a TNPF contract as a non-consensus item because stakeholders could not agree on the types of changes necessary to modify existing contracts or term sheets for distribution deferral purposes. The areas of disagreement include the number of pre-operational milestones and consequences, development security, performance assurances, and accommodations for a voltage support product. Per D.16-12-036, the IOUs were directed to eventually re-convene the CSFWG to work toward consensus on a final contract. During the call, the IOUs announced that they had selected Sedway Consulting as the industry consultant to support development of this final contract and facilitate working group discussions toward a consensus. The IOUs, Sedway, and CPUC agreed to structure meetings around terms, conditions, and provisions associated with pre-delivery, start of delivery, compensation, and all others. 

On June 19, 2018, a CSFWG working group meeting was held to further discuss development of a TNPF contract. SCE noted that the distribution deferral context is unique with specific reliability needs, shorter time frames, and more critical path and milestone assessments. PG&E described their previous experience with the DRP RFO as not being well-suited for DERs when needs require frequent dispatch but DERs are usually gauged with the 10-in-10 baseline. The CPUC Energy Division clarified that that the goal of this process should be to establish a technology neutrality within an IOU's contract structure, rather than standardizing provisions across all IOUs' contracts. 

On July 19, 2018, a working group meeting was held on the TNPF agreement to review several key terms, including product definition, resource and project description, transaction, conditions precedent, events of default, term and delivery period, customers, milestones, interconnection, termination and damages, and credit and collateral. A concern around the potential overlap between a generator’s obligation to the CAISO and to deliver under its contract to the IOU for distribution services was identified. Participants expressed a preference for flexibility around the initial delivery date (i.e., SCE’s approach), which allows the seller to extend the initial delivery date by paying delay damages and expressed a preference for standardization among on the utilities on project milestones. Overall, participants generally agreed that the key terms reviewed so far are technology neutral, and the IOUs indicated that they are open to receiving additional written comments on the materials reviewed during the meeting.

On August 28, 2018, a working group meeting was held to continue discussions on the TNPF contract, including the contract terms for capacity, metering, testing, operating parameters, scheduling/dispatch, capacity availability requirements, and maintenance/repair. Regarding hybrid resources, SCE explained that it will determine the net qualifying capacity of the energy storage component of paired BTM distributed generation and demand response solutions. Questions were also raised on the technology neutrality of this agreement if technology-specific requirements are being set (e.g., energy efficiency is considered non-dispatchable, while other DERs have dispatchability requirements), which may raise some bias. CESA was especially concerned with SDG&E’s contractual requirements that look to contract with a single counterparty for any need, require 100% reliability or default, and allow for exceptional dispatch at any time of the year. This is an approach different from that of PG&E and SCE that allows for a small band of “slack” (e.g., scale of de-rating capacity payments from 100% to 85%, then default) by procuring more DERs and contracting with multiple counterparties, thereby not placing unreasonably onerous requirements for DER providers. The other IOUs also proposed limits on exceptional dispatch over a set time period (e.g., SCE’s 15 exceptional dispatches per year on “locally constrained days”). With such a high bar for any single counterparty to take on, CESA is concerned that it may limit market participation in SDG&E’s IDER RFO.

On September 20, 2018, a working group meeting was held where the meeting topics included capacity price, compensation and payment, events of default (post-COD), and termination and damages (post-COD) for the development of a TNPF contract. The main challenge continued to be with SDG&E’s proposed contract provisions wherein sellers would be in default if projects fail to achieve critical milestones, commercial operation, provide 100% contract capacity in a performance test, deliver 100% of distribution services, provide extraordinary dispatch, or comply with a “restricted period” during the delivery term. CESA pointed out how this is especially problematic and potentially market limiting, as notifications for dispatch will generally be done on a day-ahead basis (or at least SDG&E will try to) but there may be instances of shorter, day-of notifications (8:00 am), which only leads to increased likelihood of default. SDG&E continued to justify these requirements based on their views of wires as “100% solutions” and argued that DER solutions should build in extra capacity. CESA seeks to have SDG&E modify its approach to resemble something closer to that of PG&E, which uses a Distribution Services Factor (DSF). The DSF is a ratio based on the number of times and amount of Distribution Services Buyer required for a Delivery month in relation to the amount of Distribution Services delivered by Seller in response to Buyer’s notification.

On October 24, 2018, a final working group meeting was held where each IOU discussed redlines and feedback from CESA and CEDMC as well as meter-based energy efficiency and the effect of incrementality determinations without sufficient granularity in the forecast. Overall, the IOUs were generally receptive to CESA’s feedback but disagreed in some aspects.

• SCE agreed to get rid of its “firm load” requirement in the pro forma contract and agreed to instead have charging restrictions determined by the interconnection agreement.

• SCE and SDG&E agreed to set the project development security in $/kW fashion to make securities proportional to capacity needed.

• All the IOUs clarified that incrementality definition will be defined in RFO solicitation documents rather than in the pro forma contract.

• SCE disagreed with eliminating the provision to prohibit NEM systems from participating in the RFO due to double compensation.

• SCE disagreed that telemetry requirements are unnecessary since they are required by the CAISO once a certain capacity threshold is needed (i.e., this is related to SCE seeking RA capacity from all DERs).

• PG&E and SDG&E agreed to increase the “tolerance band” for charging energy storage during restricted periods from 1% to 3%.

• SDG&E stayed firm on its requirement for exceptional dispatch (i.e., any time dispatch for full distribution capacity) to provide back-tie services for all DERs.

• SDG&E stayed firm on the need to deliver on 100% of contracted capacity, with no tolerance band for performance (i.e., act like a ‘wire’).

The IOUs have incorporated many of the suggestions into their TNPF contracts and are revisiting certain areas, such as termination rights for SCE and exceptional dispatch and 100% performance requirements for SDG&E.

On November 21, 2018, each of the IOUs submitted their final proposed TNPF contracts where PG&E and SCE incorporated some of CESA’s requested modifications but SDG&E largely held their ground on their terms and conditions. To not delay their IDER RFO launch, CESA responded with some suggestions for areas of improvement since their contracts are mostly reasonable and workable.

See CESA’s response on December 11, 2018 to PG&E’s and SCE’s Advice Letters

By contrast, CESA protested the advice letter filed by SDG&E. CESA protested because SDG&E’s 2019 IDER RFO was for a much smaller opportunity (around 400 kW) and since their TNPF contract included many untenable terms and conditions. The intent of the protest in SDG&E’s case was to make recommendations to the CPUC and SDG&E on how to best proceed with future IDER RFOs in 2020 and beyond.

See CESA’s protest on December 11, 2018 to SDG&E’s Advice Letter

On April 26, 2019, Draft Resolution E-5004 was issued that approved with modifications a TNPF contract for soliciting DERs for distribution deferral under the Competitive Solicitation Framework. Some of the key modifications made in the TNPF contract are outlined below, most of which aligned with CESA’s proposed modifications in our protests to the IOU advice letters:

• Incrementality and enabling the MUA provisions are not part of the utilities’ TNPF contract, and are therefore, not within the scope of the TNPF contract.

• One standardized TNPF contract across the IOUs and standardization of terms and conditions are difficult because the IOUs have different distribution systems and needs, so the IOUs should have some flexibility in terms and conditions.

• The 100% availability and immediate dispatch requirement have not been sufficiently justified by SDG&E as a standard contract term and such provisions can only be added to a project-specific contract based on quantitative substantiation in the candidate deferral project approval process.

• DER charging (minimal or otherwise) must be demonstrated to create a grid reliability problem and should be defined according to the operational needs of the project.

• SCE should clarify that the provision to limit the charge of energy storage only to the paired BTM PV is negotiable.

• SCE should clarify that the offeror should take the initial step of specifying the “product” it wishes to sell in circumstances where bidders only want to provide distribution capacity.

• SDG&E’s single counterparty issue is out of scope here but will be discussed separately in this IDER proceeding during the evaluation of the IDER solicitation.

CESA was supportive, as the CPUC agreed with CESA’s proposed modifications and comments on SDG&E’s 100% availability and immediate dispatch requirement, which would have created an event of default for any contracted DER providers that fail to meet these terms. Other key recommended changes on DER charging and unbundled products were also accommodated in the Draft Resolution. There were several issues regarding the single counterparty requirement, incrementality, and MUAs that were determined to be out of scope of the TNPF contract, which CESA agreed with, so we only offer brief comments encouraging resolution of these matters in broader policy-focused proceedings.

See CESA’s comments on May 20, 2019 on the Draft Resolution

On June 18, 2019, Resolution E-5004 was issued that, compared to the Draft Resolution, was revised to approve SCE’s proposed use of the Customized Calculated Savings Guidelines approach to quantify EE savings when a meter-based approach is less appropriate. To avoid regulatory delay, the CPUC modified the Resolution to require any updates to the TNPF contract be submitted on the same day as the DIDF advice letters are filed, which addressed some of SCE’s concern that delays in approval of a contract where DER technologies evolve quickly and thus may require more frequent updates. The CPUC wanted to preserve the stakeholder review process to a degree. In addition, the Resolution was revised to comment on Sunrun’s binding arbitration process, which could be done through mutual agreement by parties. Going forward, the IOUs are now directed to submit a Tier 1 Advice Letter at least 60 days prior to the DIDF solicitation, seeking approval of any proposed changes to the TNPF contract.

On June 20, 2019, the IOUs submitted advice letters updating the TNPF contracts pursuant to Resolution E-5004. Overall, each of the IOUs appeared to comply with the directives of the resolution, including SDG&E, which removed many of the previous problematic provisions. SCE also incorporated TNPF contract changes that provide product optionality and restricted charging hours, which involved determining how the charging affects settlement calculations – i.e., not to pay for losses from the battery.

Rule 21 Interconnection

Rule 21 interconnection issues have been involved in a number of CPUC proceedings, which have aimed to improve the transparency and streamlining of the interconnection process, while ensuring the reliability of the distribution grid. CESA has been leading advocacy and policy efforts in the proceedings below.

Rule 21 Evaluation

On June 27, 2019, a workshop was held to develop the evaluation plan of the Rule 21 program that aims to evaluate whether Rule 21 tariffs, timelines, and processes are in compliance with statutory requirements, benchmark utility interconnection business practices (e.g., HECO in Hawaii, National Grid in Massachusetts, Xcel in Colorado, and Con Edison in New York), and identify areas of improvement. Draft report results will be published on December 6, 2019.

On August 30, 2019, SCE submitted an advice letter on announcing that it will publish interconnection data on DG Stats in collaboration with Energy Solutions. Data will be provided on all DERs but will keep design information as confidential.

Expedited Interconnection Dispute Resolution

Straw Proposal

On May 30, 2017, the CPUC Staff released a Straw Proposal for an expedited interconnection dispute resolution process as authorized by AB 2861, a bill that CESA crafted and supported through passage. In this Expedited Process, the CPUC’s Executive Director issues binding determinations on interconnection disputes within 60 days of receiving the dispute. Determinations are made based on the recommendations of the Interconnection Dispute Resolution Panel, a technical panel of qualified electrical systems engineers that consists of at least eight members selected by the CPUC – four from utilities and four not from utilities. The Review Sub-Panel, a 4-member review panel selected from the broader 8-member Panel, is tasked with evaluating any given dispute. 

The Expedited Process will involve the following steps:

The Straw Proposal will serve as the basis for an Administrative Law Judge’s Resolution to establish the expedited process for adoption in September or October this year. The Panel and Expedited Process are proposed to be launched in March 2018. This timeframe is contingent on contracting panel members, budgetary approval, and IT system modifications. CESA generally supported this proposal as it largely complies with AB 2861. CESA offered several recommendations on the dispute resolution process, the composition of the Review Sub-Panel, and a process for linking findings from the expedited process to formal rulemaking.

See CESA's informal comments on June 23 on the Straw Proposal. 

Final Resolution

On October 12, 2017, Resolution ALJ-347 was approved that adopted an expedited interconnection dispute resolution process. Changes were made between the May 30, 2017 Staff Concept Paper and Resolution ALJ-347 to:

• Add a requirement for informal dispute resolution prior to application;

• Clarify the scope of eligible disputes for the expedited process;

• Exempt applicants from progress payments during dispute review;

• Lengthen the timeframe for utilities to initially respond to disputes from three to five business days;

• Shorten the timeframe for parties to provide additional information to the dispute’s review panel from five to three business days;

• Shorten the timeframe for submitting comments on the panel’s recommendation from ten calendar days to five business days;

• Allow for Energy Division to conduct a non-binding public nomination process for non-utility technical panel members;

• Delete the section proposing specific revisions to Rule 21 to integrate the Expedited Process and instead allow the utilities to propose tariff revisions following approval of the ALJ Resolution; and

The Resolution also established the Interconnection Discussion Forum that will provide an informal monthly venue for utilities, developers, and other stakeholders to explore a wide variety of issues related to interconnection practices and policies. The objectives of this monthly meeting are to:

• Foster proactive, constructive communication between utilities, developers, and other impacted stakeholders about issues related to implementation of Rule 21 and other interconnection rules;

• Resolve informally and/or prevent interconnection disputes; and

• Share information and best practices across utilities and developers

On December 11, 2017, the IOUs submitted advice letters to establish an expedited dispute resolution process that will issue binding determinations to interconnection disputes based on the recommendation of a technical panel within 60 days of the CPUC receiving the application regarding a particular dispute. New additions and edits in Section K of Rule 21 and a draft template for applicants for the expedited process were provided. At a later time, an evaluation of the overall process will be conducted by the CPUC.

Interconnection Discussion Forum (IDF)

On October 26, 2017, the IDF met for the first time and was facilitated by Heather Sanders, a gubernatorial appointee to the CPUC who is assisting Energy Division on interconnection. The meeting reviewed the charter of the IDF, discussed shared interconnection objectives, reviewed interconnection processes and timelines, and discussed current interconnection issue themes. The discussion focused on the inconsistencies in the application of the rules across the IOUs. Some of the key highlights and takeaways from this meeting are:

• The IOUs conveyed their views that as DER and renewable penetration grows, interconnection studies will require more detailed analyses.

• The IOUs will seek to be consistent and adhere to some timeframes, but they also cautioned that these study processes can vary depending on the location of interconnection.

• The IOUs pointed to Aliso Canyon energy storage procurement and interconnection as an exception.

• The developer community sought greater transparency into other parties’ interconnection issues to understand areas of improvement and to promote cross-learning

On December 7, 2017, a forum was held where the IOUs discussed the most common causes of interconnection application deficiencies. The IOUs also clarified how each IOU does not require application withdrawal and resubmittal for reductions in solar system sizes after initial Rule 21 application submission.

On April 3, 2018, a monthly IDF was held to update stakeholders on the expedited dispute process panel establishment pursuant to AB 2861. As a follow-up to a previous IDF meeting, PG&E provided an update on how it is piloting two process changes for small NEM-paired storage systems and on how it is in the process of adding online payment capabilities for NEM-paired storage projects by the end of 2018. Finally, the IOUs provided clarity on when a project stays in Rule 21 and on when it needs to move through the WDAT interconnection process for projects that are greater than 1 MW. Specifically, the IOUs clarified that only projects under 3 MW are eligible for Fast Track review and only projects that fail Rule 21 Screen Q (electrical independence test) are required to undergo a WDAT Cluster Study. The IOUs also clarified that telemetry requirements apply for all projects above 1 MW, but the IOUs have been pushing to lower the threshold in the Rule 21 proceeding (R.17-07-007) for when telemetry is required.

On June 25, 2019, an IDF meeting was held to discuss disputes of interconnection agreements for forest bioenergy facilities in high hazard zones and whether it is necessary to require “separate facilities” need to be installed when existing facilities serving on-site load may have sufficient capacity. Interestingly, Sunpower also lead a discussion around streamlining interconnection processes upon ‘move-in’, especially as rooftop solar is being built into the 2019 building code.

Rule 2/3/15/16 Interplays

On May 15, 2018, a workshop was held where each of the IOUs covered the Rules 2, 15, and 16 tariffs to help attendees understand the interplay with Rule 21 interconnection processes. Specifically, the workshop detailed various scenarios on how costs for upgrades to service and line extensions would be allocated and recovered. Importantly, several outstanding policy questions were raised, such as whether load and generation should be considered together when the IOUs calculate load impacts and whether interconnection should be reviewed at a system rather than individual DER interconnection level. In addition, the IOUs raised the question of whether NEM-paired storage systems should be studied similar to non-export storage systems (i.e., expedited review for charging restrictions during peak load times), given that there is currently no charging restriction, leading to a review of maximum charging impacts in the load study. Additionally, in the case of microgrids, an idea was raised on whether the customer could potentially release the IOU from the liability of obligation to serve.

Solar+Storage Interconnections

On September 20, 2018, the CPUC focused on interconnection of solar-plus-storage systems and exploration of ways to reduce application and study time, especially as the IOUs have witnessed an explosion in NEM-paired storage interconnection applications every year. To ensure timely Fast Track screening, the IOUs discussed how interconnection applicants should verify inverter voltage, verify impedance information, and ensure all data required to complete Supplemental Review is provided and accurate in the interconnection applications – areas that the IOUs identified as “common deficiencies” in the Rule 21 process. The IOUs also presented on functionality improvements that they are in the process of implementing, including online payments, document uploading capabilities, electronic signatures, developer/installer support, and pre-approved single-line drawings.

On March 5, 2019, a workshop was held to debate the differing IOU interpretation of “customer electrical requirements” phrase as it relates to NEM system sizing. Developers cited examples of detrimental impacts of different interpretations, such as the “rule of thumb” for new construction load. For new construction, there is a rule of thumb that a house will use 2 W per square foot. Load justification forms are needed to install generation beyond the assumed site load. Additionally, developers cited the need to have historical demand data or an EV before allowing for generation up to the EV-ready home. In other words, a full year of increased load is needed before installing on-site generation to meet it, which prevents homes from being ‘wired’ to be EV-ready.

Totalized Metering

On December 3, 2018, SCE and AMS presented an overview of interconnecting Rule 21 non-export generation at customer locations with “totalized metering” that involves a customer at a single premises with a service account supplied by multiple service drops, each with a separate meter, who wants to reduce the load for the entire location. The proposed interconnection configuration would require the customer to export energy from the storage/generation located behind one meter across distribution facilities to reduce the load associated with the other meters, in violation of Rule 21 non-export requirements. SCE explained that it is in this situation because of service limits at 4,000 amps, which causes the separation of metering. PG&E noted that it has a 5,000 amp limitation.

The solution that SCE and AMS arrived at was to convert certain distribution facilities to “added facilities” and establish a new operating point of common coupling that meets the needs of the customer and comply with Rule 21 non-export requirements. By doing this conversion, the customer no longer flows power over the distribution system and the ratepayer is no longer on the hook for any upgrades. AMS explained that, without this solution, the battery storage system would need to be limited to the specific connected load (single meter). For existing distribution facilities converted to added facilities, the customer will be responsible for a monthly pro rata charge (1.42%) based on the usage of the facilities. This solution does not apply for customers on two different circuits or two distinct points on the distribution system. SCE said this solution did not require any rule or tariff changes because it was an application of existing tools available – i.e., the “added facility” provision of Rule 2 – with the pro rata element of the solution being the only thing unique about it. The other IOUs will report in a few weeks on whether this type of solution would be workable for them as well, but they have not encountered these issues.

Rule 21 Interconnection 2011 (R.11-09-011)

Background

On September 22, 2011, the CPUC initiated this rulemaking to review, and if necessary, revise the IOUs' Electric Rule 21 Tariff. This rulemaking aims to reform the CPUC’s Rule 21 that streamlines and improves distribution-level interconnection rules for distributed generation (DG) and energy storage. The first phase reformed the Rule 21 interconnection procedure and the most-recent phase took up interconnection cost certainty and energy storage-specific issues. The utilities only addressed the issue of non-exporting energy storage in an initial filing in March 2015, with a second filing thereafter addressing the utilities’ cost certainty proposal. 

For an overview of Rule 21 energy storage interconnection, please see the IOU webinar here.

2016 Rule 21 Revisions

On November 18, 2015, the IOUs along with several other parties filed a Joint Motion that proposed to apply Rule 21 principles to the treatment of load related to energy storage and to increase their transparency for the load-side interconnection review process through its proposed Interconnection Guide (akin to the CAISO’s Business Practice Manual). Through an Advice Letter process, the utilities also committed to working with CESA members on outlining a process for expedited review of standardized non-export systems and of systems with advanced inverter functionality.

On June 23, 2016, D.16-06-052 closed the proceeding and approved the Joint Motion, which includes:

• 25% cost envelope pilot policy for interconnection cost certainty

• Unit Cost Guide and Enhanced Early Application Report

• Development of Interconnection Guide that includes details on energy storage charging load processes

• Revisions to the Rule 21 Tariff to develop streamlined interconnection processes for non-export energy storage and for those using Bosch's AC/DC converter

• Modifications to the Interconnection Agreement and Application to capture energy storage load information for the applicable agreements

• Pathway forward for development of an Inadvertent Export Option in the Rule 21 Tariff

On July 6, 2016, Commissioner Sandoval submitted a Concurrence to D.16-06-052 that drew parallels to this decision improving the Rule 21 interconnection process to the communication standards adopted in the telecommunications industry that made the Internet more accessible. Commissioner Sandoval praised the decision as one that will unleash a new era of energy competition, innovation, and investment. 

On July 8, 2015, the IOUs filed Tier 1 Advice Letters per the requirements of D.16-06-052. 

Energy Storage Load Treatment Clarifications

Per D.16-06-052, the IOUs added the following language to their Rule 21 tariffs: 

“B.4. Interaction with other Tariffs for Storage Charging  Load Treatment For retail Customers interconnecting energy storage devices pursuant to this Rule, the load aspects of the storage devices will be treated pursuant to Electric Rules 2, 3, 15 and 16 just like other load, using the incremental net load for non-residential customers, if any, of the storage devices.”

Non-Export Storage Expedited Interconnection Criteria

On August 18, 2016, the IOUs held a workshop to discuss an initial proposed list of criteria for an expedited interconnection process for non-exporting storage facilities. During the workshop, the IOUs and stakeholders discussed the interconnection study and implementation (technical focus) and interconnection applications and agreement (administrative focus). 

On October 21, 2016, each of the IOUs submitted Advice Letters to revise Rule 21 (see new Section N) to establish an expedited interconnection process for standalone, inverter-based, non-exporting energy storage facilities. The eligibility criteria are that projects:

• Cannot exceed 0.5 MW in aggregate inverter and/or rectifier nameplate rating (but any energy storage kWh rating may apply)

• Must be behind a single, clearly marked, and accessible disconnect

• Only Screen I Protection Options 3 and 4 are eligible, as well as potentially AC/DC converters pending their lab results

• Must be at a single retail meter point of interconnection

• Must have a single or coordinated control system for charging functions

• Must operate under “Charging Mode 2” wherein charging functions do not increase the host facility’s existing peak load demand

• Must have a UL-1741 certified inverter

• Must include a single-line diagram and description of operations

• Must meet all Electric Service Requirements

For projects meeting the above criteria and submitting all the relevant documentation, no distribution or network upgrades are required. Interconnection requests will be processed within 15 business days for SCE, 20-30 business days for PG&E, and 30 business days for SDG&E, from the date the applicant’s request is deemed valid and application fees are received. Further, to help facilitate this expedited processing, the IOUs intend to issue a preliminary Generator Interconnection Agreement as soon as the request is deemed valid and complete (in parallel with the technical review process). The new expedited interconnection process is expected to be completely in place by the end of Q2 2017 for SCE (end of Q3 2017 for PG&E and SDG&E).

On November 10, 2016, three parties submitted protests focused on the need to set uniform criteria and requirements across each of the IOUs. 

On November 21, 2016, the CPUC suspended the Advice Letters to provide it with more time for review.

On February 6, 2017, SDG&E filed a Supplemental Advice Letter that changed the business days for the expedited process from 30 business days to 15 business days to be consistent with the other IOUs and discussed how it will formally implement a pilot-like approach for the expedited interconnection process. SDG&E indicated that it intends to file an Advice Letter reporting on the outcome of the pilot on November 1, 2018.

In March 2017, the CPUC approved the IOUs' advice letters proposing modifications to Rule 21 to establish an expedited distribution interconnection process for eligible non-exporting storage facilities. To be eligible, energy storage facilities must be non-exporting, smaller than 500 kW and meet other technical criteria. Eligible projects that provide additional information to the utility upfront will then be issued a draft generator interconnection agreement within an expedited timeframe as discussed under the IOUs' advice letters. In response to concerns that Rule 21 provisions implementing the expedited process did not support tariff principles of technological agnosticism and consistency across IOUs, Energy Division approved the expedited process under a one-year pilot-like approach. At the end of the reporting period (July 1, 2017 through June 30, 2018), and no later than September 1, 2018, the IOUs shall file advice letters reporting on program outcomes, at which time the CPUC may determine whether the provisions of the expedited process should be continued, modified, and/or withdrawn. The Commission may also consider changes to the $800 application fee based on program data collected during the reporting period. Absent action from the CPUC, the provisions of the expedited process will remain in effect as written.

On August 31, 2018, the IOUs circulated an information-only advice letter to report on a one-year pilot (June 30, 2017 to June 30, 2018) for an expedited interconnection review and process for 0-500 kW non-export energy storage applications, which would be compared to the interconnection timeline for similar projects that interconnected in 2015-2016. PG&E’s results are highlighted below, which show demonstrable improvements to the time and efficiency of processing Rule 21 applications for eligible non-export energy storage applications.

Similar results were reported by SCE and SDG&E. SDG&E experienced a reduction from 4 business days for the control (interconnection requests during the 2015-2016 period) to 1.7 business days for the pilot (interconnection requests during the 2017-2018 period) on average to go from an application deemed complete to a draft agreement being provided to the applicant. SCE reported that it saw the median process time decrease from 23 days (control) to 16 days (pilot). Based on these results, PG&E observed that the pilot results may reflect IT improvements, and following this pilot, PG&E recommended that existing Rule 21 timelines remain intact so that PG&E can focus on implementing these improvements rather than diverting resources to support an additional and overlapping technology-specific compliance timeline. SCE, on the other hand, proposed to extend the pilot for one year (through August 2019) in order to gather additional data. Finally, SDG&E indicated that it would not be opposed to making this expedited process a permanent part of Rule 21, though it would not recommend adding other technologies to be part of an expedited process at this time.

On August 30, 2019, SCE submitted an advice letter on updated pilot results for the expedited interconnection of non-exporting storage facilities. The median interconnection timeline went from 23 business days in 2015-2016, 16 business days in 2017, and 15 business days in 2018, but SCE observed a significant decline in demand for this expedited process, going from 87 such requests in 2017 to 34 in 2018. SCE, as a result, proposed to discontinue this pilot.

On September 30, 2019, a workshop was held where CESA raised the issue of SCE’s WDAT interconnection proposal. Additionally, only SCE shared that they have updated results on the expedited process for eligible non-exporting storage facilities, though they all did not support continuation of the pilot Section N process. However, stakeholders like CESA raised concerns with how the pilot did not generate lessons learned that could inform Rule 21 tariff changes to streamline interconnection for non-exporting storage facilities.

On December 16, 2019, the IOUs presented results on their Non-Exporting Storage Facilities Pilots, with a particular focus on “lessons learned” given the lack of such insights in their advice letter filings or at the previous IDF meeting.

• From June 2017 to June 2018, PG&E was able to reduce the time from application deemed complete and application received to commercial operation date by 42.8% and 33.8%, respectively, in the pilot. PG&E concluded that an expedited process is no longer necessary because the cycle time increased in the post-pilot period, pointing to the implementation of the new ACE-IT portal as possibly driving longer processing timelines, though the portal will, in the long term, improve and simplify the application process across multiple portfolios of projects. Instead of continuing Section N, PG&E pointed to the story of NEM-paired storage, where frontloading interconnection applications, online payments, and generator lookups could save months in the process.

• From July 2017 to July 2019, SCE found that the time from application deemed complete to draft interconnection agreement dropped from a median of 23 days prior to the pilot (2015-2016) to 16 days during the first pilot period and to 15 days during the second pilot period. SCE reported that it allowed applicants to provide comments on front-loaded interconnection agreement in parallel with technical review, created customer naming requirements, and authorized signatory one-pager to educate interconnection customers. Some of the common reasons for delay included incorrect entity names submitted by the interconnection customer, incorrect single-line diagrams, selection of protection options, and internal delays.

• From October 2017 to September 2018, SDG&E reported negative 1.7 business days from receipt of the interconnection request and issuance of a draft interconnection agreement, which occurred due to concurrent issuance of the invoice and draft interconnection agreement upon application being deemed complete. SDG&E is not opposed to making Section N a permanent part of the Rule 21 process but recommended additional technologies be included and claimed that additional items warrant consideration, including its online portal with automated AHJ electrical releases and auto-population of existing generation information.

However, key areas of improvement were hard to glean from the pilot results due to the lack of a research question and hypothesis, with the data showing correlations but no means to discern causation on key modifications that would streamline the interconnection process. CESA advocated for keeping Section N until something useful or next steps are identified from the pilots.

Public Interconnection Guide

An Interconnection Guide will specify size thresholds subject to 'cursory' load review and proposed charging profiles to avoid potential system upgrades. 

On October 21, 2016, the three IOUs published their Storage Charging Interconnection Load Process Guide, which provides an overview of the study and processing details related to the charging/load aspects of an energy storage Interconnection Request, as well as the interaction of Rules 2,3,15, 16 and 21. Specifically, the Load Guides address specific size thresholds for cursory load review, charging profiles to avoid system upgrades, and cost responsibility of load-related impacts. Each IOU has the same definition for charging ‘modes’: Mode 1 charges only from on-site generation, Mode 2 charges from the distribution grid but without increasing host facility peak load, and Mode 3 charges from the distribution grid at any time.

Projects may be studied in two parallel paths for generation and load, respectively, followed by a ‘reconciliation’ process. Some upgrades or modifications required for the generating mode may overlap with upgrades required for load (charging). The upgrades for load will be considered first and treated pursuant to the load tariffs.

A request to make any change to the Load Guide, including any addition, edit, deletion, revision, or clarification, must be initiated by the submittal of a Proposed Revision Request (PRR).

Unit Cost Guide

On November 9, 2015, a joint motion by parties was filed that proposed the development of a Unit Cost Guide., which helps provide better interconnection cost understanding for installers. The Unit Cost Guide gives generation developers a readily available price list of typical interconnection facilities and equipment so that prospective interconnection applicants are able to immediately obtain typical cost data. 

On September 21, 2016, the first version of the Unit Cost Guide was published in Advice Letter filings. The IOUs worked together to develop a consistent Guide format and includes:

• Cost information and various requirements for interconnection facilities and distribution upgrades

• Forecasted annual adjustment for five years to provide estimate for future procurement timing

• "Illustrative" project examples and calculation assumptions

• Utility O&M and cost recovery calculation methods

The listed costs may vary by utility and are not binding - i.e., intended to provide additional cost transparency and be used as a point of reference. The IOUs are required to update the Guide annually in Q1, per D.16-06-052.

On April 6, 2017, the 2016 Unit Cost Guides was officially posted by each of the IOUs. Annual updates will occur in Q1 of each year through a stakeholder input process.

Enhanced Pre-Application Report

The Enhanced Pre-Application Report will give generation developers better specific cost and associated timing information on a project-specific basis. The existing Standard Pre-Application Report will still be available as an option for customers. The selection of the Enhanced Report will be assessed a $100 administrative fee. The IOUs intend to automate as much of the form and related processes as possible.

The Enhanced Pre-Application Report, offered in “Primary Service” and “Behind the Meter Interconnection” packages, enables project developers to make more informed decisions about where to pursue projects before significant financial investments are made. Reports contain additional information on absolute and day-time minimum load for relevant line sections, existing upstream protection devices, available fault current, transformer data, secondary service characteristics, and primary service characteristics. One or both enhanced reports may be requested concurrently with the Standard Pre-Application Report for fees ranging from $300 to $1,325.

Cost Envelope Option Implementation

The 25% cost envelope option (CEO) will provide applicants with greater interconnection cost certainty while incentivizing the IOUs to accurately measure interconnection costs. D.16-06-052 required that the CEO be enacted upon the cost estimate provided to the developer in the Generator Interconnection Agreement (GIA) and required that the estimated and actual cost documentation be itemized with exact breakdowns of labor, O&M, and capital expenditures.

On August 22, 2016, PG&E and SCE submitted Advice Letter filings to modify its Rule 21 tariff and associated interconnection applications and agreements to establish the Cost Envelope Option (CEO) Pilot.

On September 12, 2016, IREC protested the Advice Letters and requested that a timeline of 20 business days be established for cost envelope estimate re-evaluations if an applicant identifies and suggests minor changes to the interconnection application.

On December 15, 2016, in response to IREC's Protest, SCE and SDG&E submitted supplementary Advice Letters to provide greater transparency regarding the components of the estimated and actual costs that are provided to the developers under the cost envelope framework and to reflect IREC’s suggested language on re-evaluation periods for cost envelope estimates. 

On May 25, 2017, Resolution E-4850 was issued that approved Rule 21 revisions to establish a 25% cost envelope for interconnection-related expenses. A developer’s responsibility for eligible interconnection costs is limited to plus or minus 25% of the cost estimate provided by the IOU in the Generator Interconnection Agreement. Any costs above or below that estimate may be recovered by the IOU in a General Rate Case. This option will be piloted for five years. Resolution E-4850 incorporated some revisions to the IOUs' initial advice letters. Among these changes were a determination that revisions to cost estimates, if necessary, are to be developed within the same timeframes allotted for preparing the initial estimates. It also directed the IOUs to provide information that will allow the CPUC to review the level of detail provided in cost estimates. 

On December 3, 2018, a workshop was held that reported on the CEO pilot status and results and provided an overview of meter totalization. SCE reported that, in Year 1 of the CEO pilot, it received 14 requests for the CEO with only 1 customer that paid the deposit and proceeded with CEO review, which represents a small share of the total number of interconnection applications (400+). PG&E and SDG&E also reported the lack of customer interest in the CEO option. At the meeting, stakeholders discussed that the lack of interest may be tied to the additional upfront time that developers need to gain cost certainty not being worthwhile, which may be a greater issue for larger BTM and wholesale installations that are at greater risk of distribution upgrades. Other reasons for the lack of interest may be new tools available to provide cost certainty, such as the unit cost guide and the ICA data on available hosting capacity.

Advanced Inverter Inadvertent Export Option

An Advanced Inverter Inadvertent Export option is intended to allow for some uncompensated export without requiring expensive reverse power relays or other equipment. This is important because inadvertent export could occur, for example, if a large portion of onsite loads being met by onsite generation were to suddenly drop (e.g., an air-conditioning unit trips off). Because it takes a short amount of time for an inverter to recognize that onsite loads have dropped below the amount of energy output from the onsite generation, there may be a brief period where the system net exports to the grid. However, provided the duration and magnitude of any such inadvertent export during this period is relatively small, these systems could be evaluated as effectively 'non-exporting'. Establishing a standard for inadvertent export may therefore streamline the interconnection process for such projects. 

On August 8, 2016, the IOUs filed a Status Report that refined Rule 21 Section N tariff language to apply to smart inverters, which mimics language from Hawaii Electric’s (HECO) recent Rule 14H Tariff revisions. According to the Status Report, inadvertent export is allowed as long as the generating facility:

• Is composed of UL-1741 listed non-islanding inverters

• Has a maximum 100-kW load with 2 seconds to de-energize or halt production if exceeding 100 kW of inadvertent export

• Has all of its output consumed by host load

• Limits inadvertent export to one-hour per billing cycle and up to 30 seconds per occurrence with 2 seconds to de-energize or halt production if exceeding 30 seconds of inadvertent export

• Utilizes a third-party-certified control system to govern the level of inadvertent export based on the ‘net result of current from all phases’

Stakeholders had disagreements with the 100-kW threshold and whether control systems can technically respond within two seconds to any crossing of the thresholds, but the IOUs maintained this time delay to avoid exposing adjacent neighbors to poor voltage quality. 

On September 2, 2016, each of the IOUs filed Advice Letters seeking to modify Rule 21 to implement a new Inadvertent Export option for generating facilities that utilize UL-1741 or UL-1741 SA-listed grid support (non-islanding) inverters. Specifically, an additional option (i.e., Option 6) was incorporated under Screen I, which reviews whether power will be exported across the point of common coupling, and Screen M was modified. 

On October 11, 2016, five companies protested the Advice Letter filings for subjecting these systems to Screens J through P despite passing Screen I, and for applying daily energy export limits despite two-second disconnect requirements.

In their Responses to the Joint Stakeholders, PG&E and SDG&E expressed surprise that there are still outstanding issues since the Advice Letters were intended to be made “if agreement is reached.” PG&E responded to each of the points raised in the Protest, which it hopes to clarify concerns and result in consensus:

• Option 5 and 6 Inadvertent Export Projects have the ability to export energy across the PCC for up to 60 seconds, which can cause distribution system issues (e.g., excessive voltage fluctuations)

• The Fast Track Review process is not complete after Screen I, like it is for projects selecting one of the first four non-export options since power may be exported across the PCC under Options 5 or 6

• The inclusion of the 30-day export provision in Section Mm should not replace the daily energy export limit because the more instantaneous measure helps avoid potential issues around voltage fluctuation that can cause voltage flicker issues with existing customers

On October 20, 2016, the CPUC suspended the Advice Letters to provide it with more time for review.

On March 2, 2017, a joint party of solar, energy storage, and inverter providers withdrew their protest of the IOU advice letter filings revising Rule 21 tariffs since the IOUs updated their advice letter to reflect stakeholder issues and concerns. The CPUC approved revisions to implement a new inadvertent export option for generating facilities that utilize UL-1741 or UL-1741-SA listed grid-support (non-islanding) inverters. Projects selecting this option will now be able to bypass certain technical screens during initial review and be allowed to inadvertently export power within specified parameters. 

Bosch AC/DC Converter UL Test Results

On November 22, 2017, with the IOUs and Bosch having received and mutually agreed upon test results for Bosch’s AC/DC converter by Underwriters Laboratory (UL), the IOUs filed advice letters requesting CPUC approval of amendments to Rule 21 tariff and forms, as applicable, to address the use of these UL-certified AC/DC converters, a one-way only device that takes AC power from the distribution system and converts it into DC power for DC loads without allowing any power or energy to be exported to the distribution system. Specifically, the expedited process will allow certified AC/DC converters to bypass Screens B-D and F-M. The IOUs pushed back against comments by Bosch and Tesla to modify backfeed limitations, which are addressed in IEEE 1547, to pre-approve for all Fast Track screens without seeing how they perform, and to include non-export systems with inadvertent export that meet the criteria of an AC/DC converter (needs third-party certification). 

On December 21, 2017, the CPUC staff suspended the advice letters to provide it with more time to review. 

Smart Inverter Working Group (SIWG)

Generating resources interconnecting to the utility grid via Rule 21, which produce direct current (DC) power, require an inverter to convert the DC from the generating resource to the voltage and frequency of the alternating current (AC) distribution system. The SIWG was thus established in early 2013 to develop proposals to take advantage of the new, rapidly advancing technical capabilities of inverters. The SIWG was tasked with making technical feasibility assessments and recommendations (not discuss compensation mechanisms). 

Phase 1 of the SIWG developed seven autonomous inverter functions, adopted in D.14-12-035, that will be mandatory for all inverter-connected DERs in September 2017. 

Phase 2 of the SIWG outlined the default communication protocols that govern how IOUs communicate with individual DERs and DER aggregators. 

Phase 3 of the SIWG developed recommendations for additional advanced functions that enable operational protocols or transactional models to provide inverter-based DER grid services. The SIWG submitted its Phase 3 recommendations in March 2016. These advanced funtions represent a higher, more forward-looking level of DER monitoring and control, in which DERs can be leveraged via Phase 2 communications to provide a material response to certain grid conditions. These advanced functions include:

• Commanding DERs to connect or reconnect

• Setting or limiting real power generation

• Increasing or decreasing real power output in response to voltage or frequency excursions

• Providing reactive current support in response to dynamic variations in voltage

• Scheduling to allow DERs to autonomously provide an optimal operational response to a triggering grid condition, such that individual commands do not have to be sent each time the need arises

In February 2015, the SIWG completed its recommendations for Phase 2 communications including specifying the default communication protocol standard IEEE 2030.5, which defines a framework for communications between the utility and the generating resource. 

On September 8, 2016, the Underwriters Laboratory (UL) announced the approval of the new UL 1741 Supplement SA to test and certify inverters and other utility interconnected distributed generation equipment for grid support functions enabling smart and safer reactive grid interconnection.

On September 13, 2016, each of the IOUs filed Advice Letters seeking to modify Rule 21 to require inverter-based generators to use smart inverters in order to interconnect under Rule 21, starting on September 8, 2017. These mandatory requirements are intended to comply with D.14-12-035 and are in line with the 2014 recommendations from the SIWG.

On November 17, the SIWG held a workshop to discuss the implementation of Phase 2 and Phase 3 recommendations. The workshop discussed several Phase 3 issues, including key DER data monitoring situations, DER "cease to energize" situations, maximum real power mode limits, frequency-watt emergency modes, cybersecurity requirements, and more. Many of these technical issues have cross-overs with the existing IEEE 1547 requirements, and the question in the workshop was whether to adopt and/or refine similar requirements for California's Rule 21 tariff.

On December 20, 2016, the IOUs each filed Tier 3 Advice Letters to revise Rule 21 that incorporates the technical requirement changes that implemented Phase 2 and Phase 3 recommendations in compliance with D.16-06-052. These revisions include agreed-upon technical requirements, testing and certification processes, and effective dates for Phase 2 communication protocols and Phase 3 additional advanced inverter functions. In the absence of consensus, the IOUs are required to file a status report and work plan.

On April 7, 2017, Resolution E-4832 was approved that incorporated the SIWG’s Phase 2 recommendations on communication standards as Rule 21 tariff revisions. These standards would become requirements for generating facilities utilizing inverter-based technologies. The recommendations define the communications capability of smart inverters, specified pathways of communication between the utility and the generating facility, and the default communication protocol standard. The mandatory date for Phase 2 functionality for each of the IOUs is the later of: (a) March 1, 2018, or (b) nine month after the release of the SunSpec Alliance communication protocol certification test standard (or the release of another industry-recognized communication protocol certification test standard). Meanwhile, the CPUC and CEC are still working with the SIWG to reach a consensus on outstanding issues related to the Phase 3 functions and the SIWG’s recommendation on synchronization with the IEEE 1547 standard, such that the IOUs may file Tier 3 Advice Letters in June 2017 proposing tariff revisions to Rule 21.

On September 8, 2017, all new interconnection applications for inverter-based generating facilities, including inverter-based storage facilities, interconnecting under the Rule 21 are required to utilize UL 1741 Supplemental A (SA) certified inverters. Non-exporting storage facilities are not exempted from this requirement. For stakeholders interested in DER aggregations, they objected to the adoption of the communication and scheduling capability requirements at this time. 

On August 17-18, 2017, the IOUs filed advice letters that modify each of their Rule 21 tariffs to reflect the following Phase 3 functions:

Many of the above changes will take effect 9-12 months after approvals of either the advice letters, IEEE 1547.1 standard, or Sunspec Alliance approved test procedures – i.e., in Q2 or Q3 2018. For smart inverters that include one or multiple energy storage systems, the available kWh energy will need to be communicated as an aggregate of all the energy storage systems.

On September 6, 2017, multiple protests were filed mainly due to the IOUs requiring the activation of Phase 3 functions (rather than setting requirements for these capabilities) and because it is premature to require these functions without any determination on how these functions would be compensated. Concerns were raised on the unnecessary PV curtailment risks of the proposed Volt-Watt and Frequency-Watt modes, on the California-specific nature of scheduling standards that may inhibit California’s inverter market, and on the complexity of staggered product releases of these functionalities. Given the number of concerns raised, a workshop will be held on October 25 to confirm areas of consensus and propose next steps.

On October 25, 2017, a workshop was held to discuss and, if possible, resolve issues raised in the IOUs' advice letters to incorporate Phase 3 recommendations. The solar parties argued that there are a number of functions, such as volt-watt and scheduling capabilities, where the need has not been adequately demonstrated and compared against the potential impact to customers (e.g., NREL found that some customers could see up to 10% curtailment annually). They viewed these technical considerations as pre-empting policy discussions that are underway or are scheduled for consideration, and believe that these functions should be required capabilities at this time. 

Rule 21 Interconnection 2017 (R.17-07-007)

Background

On July 21, 2017, the CPUC issued an Order Instituting Rulemaking (OIR) for a new interconnection proceeding, with the preliminary proposed scope being the incorporation of the ICA into Rule 21 and other outstanding issues remaining from this proceeding (as listed in the Joint Motion on energy storage). The ICA tools use power flow analysis to determine the ability of a circuit to host distributed energy resources. Incorporating the ICA tools into Rule 21 may better inform interconnection siting decisions and further streamline the Fast Track process for certain projects. This proceeding will address some or all of the issues listed below in four tracks. The proceeding should be largely positive for CESA members as it included most of the scope of issues on CESA's priority list. 

See CESA's informal comments on June 1, 2017, comments on August 2, 2017, and reply comments on August 25, 2017 on the Order Instituting Rulemaking.

In summary, CESA indicated that its main priorities are in building on the work from the closed proceeding, and in addressing issues from the DRP and Storage proceedings. On the latter point, there may be good opportunities to have joint workshops for stakeholders in both those proceedings to ensure implementation of whatever is the outcome from those proceedings. CESA was therefore largely supportive and includes just small revisions to the scope of issues. CESA also supported the inclusion of EV interconnection issues as a placeholder, recommended the removal of lithium-ion disposal from the scope as commented by the CPUC’s new Office of Safety Advocates (OSA), and noted that the four proposed tracks did not need to occur sequentially.

On October 2, 2017, a Scoping Memo was issued on October 2 that established three phases to this proceeding:

• Phase 1 involve urgent and/or quickly resolvable issues, including the streamlining of Rule 21 interconnection by incorporating the ICA methodology, planning and billing of distribution upgrades, application processing and review, smart inverter requirements, and coordination with the IDER proceeding.

• Phase 2 involves ratesetting issues requiring coordination with the DRP proceeding.

• Phase 3 issues deal with small and multi-jurisdiction utility rules.

On November 16, 2018, an Amended Scoping Memo was issued that re-scoped certain issues into Working Groups #3 or #4 or into the Interconnection Discussion Forum (IDF), and posed questions to parties on their opinions for the most efficient and appropriate way to resolve Rule 21 interconnection issues in a timely manner, especially considering new issues keep emerging. Most parties agreed that the IDF was an appropriate forum to discuss best practices and resolve disputes but not to make technical fixes or improvements to the Rule 21 process. The IOUs expressed that no more additional issues be added to the scope of the proceeding, which is not surprising given the wide range of issues already being considered already. Others expressed concerns about an always-changing scope of the proceeding that creates uncertainty, instead recommending that interconnection issues be addressed in set intervals.

Working Group 1

Background

Below are some of the CESA-relevant issues and their corresponding Working Group (WG) and item number. WG 1 began meeting on October 16, 2018 and submitted a proposal on March 15, 2018:

• Should the CPUC clarify the definition of “complex metering solutions” for storage facilities and, if so, how? (Item 2)

• How should the CPUC clarify the definition of a “material modification” to a project and what should be the procedures for processing these modifications? (Item 3)

• As the penetration levels of DERs increase, what changes to telemetry requirements should the CPUC adopt to ensure adequate visibility while minimizing cost? (Item 4)

• Should the CPUC require activation of advanced functionality in Phase 1 compliant inverters installed before September 9, 2017 and, if so, how? (Item 5)

• Should the CPUC require the IOUs to develop forms and agreements to allow DER aggregators to fulfill Rule 21 requirements related to smart inverters? If yes, what should be included in the forms and agreements? (Item 6)

On August 15, 2018, a Ruling was issued that directed parties to respond to a set of questions on the Working Group #1 Report, which focused on whether software and firmware controls can ensure safe and reliable interconnection, whether the Screen Q exemption should be more broadly applied than just for NEM systems, and whether the reduced threshold for telemetry requirements are reasonable.

CESA focused on the broader theme of ensuring that Rule 21 processes focus on the fundamental physical reliability aspects of interconnection. In line with that, CESA commented on how the Screen Q exemption proposal (Issue 1) should consider how non-export, non-NEM energy storage systems may also qualify for this exemption given how the electrical independence test is determined by power flows and short-circuit duty contribution. Next, on issues related to Rule 21 modification processes (Issue 3), CESA addressed some worst-case scenario concerns about how many of these same concerns can be and are already being addressed by software and firmware controls, thus allowing for notification-only and/or abridged interconnection applications when doing regular maintenance/replacements or increasing energy storage capacity without changing the inverter capacity or operational profile. Finally, CESA commented on how the IOUs still need to provide greater justification and data into why the threshold for telemetry requirements need to be reduced, while also highlighting how there may be potential alternatives to requiring telemetry for all small DERs between 250 kW and 1 MW to provide situational awareness on their grid.

See CESA’s comments on September 5, 2018 on the Ruling

Fast Track Screen Q Modifications (Issue #1)

Background

CalSEIA has led the effort on Issue #1 to modify Fast Track Screen Q (Rule 21, Section G.3.a) to minimize the number of DER projects subjected to transmission cluster studies, which are significantly longer than typical Rule 21 processes (2+ years later) and require studies in the Cluster Application Window in March of every year. Screen Q is the Electrical Independence Test (EIT) conducted as part of the Rule 21 Independent Study Process (ISP) that assesses whether the proposed interconnection request has any interdependencies with earlier-queued interconnection requests under any tariff and whether its contribution is of sufficient size to make an impact on existing Network Upgrades or potentially cause a new Network Upgrade on the CAISO system. Projects that are found to have interdependencies will fail Screen Q, be withdrawn from Rule 21, and have the option of applying for interconnection under the Transmission Cluster Study Process of the Wholesale Distribution Access Tariff (WDAT), which is administered by the host IOU, CAISO, and any Affected Systems. 

CalSEIA was concerned that projects will increasingly be caught in the cluster study process even though their contribution to transmission system upgrades is not significant. The current exemption for Screen Q is 500 kW, which was chosen by settlement parties in the last major update to Rule 21 in 2012, but CalSEIA aimed to raise the size threshold for the exemption to less than or equal to 1 MVA NEM nameplate capacity, given the "negligible impact" on the transmission system. The IOUs appeared to be agreeable to this change given that the IOUs have seen few projects fail the ISP (only 9 projects for PG&E, 1 for SCE, and 0 for SDG&E) and because projects of that size will often not need network upgrades. This threshold also aligned with the 1 MW threshold for NEM cost allocation. Additionally, CalSEIA aimed to expand the Screen Q exemption from NEM only to all projects, which has lacked consensus in the working groups. Note that the change from rating this threshold in MVA instead of MW was because inverters and transformers were highlighted as being increasingly rated in such a way.

Proposal Development

On March 15, 2018, four proposals were developed. The first proposal (1a) was to expand the existing Screen Q exemption for NEM facilities with net export less than or equal to 500 kW by increasing the exemption size threshold to 1 MVA nameplate capacity. This core proposal had consensus from the working group. The IOUs observed that projects less than 1 MVA commonly did not require upgrades and agreed that a conversion from MW to MVA is appropriate because MVA is how inverters are measured. IREC proposed a variation of this core proposal that sought to set this threshold based on net export capacity as opposed to nameplate capacity because net export is the more relevant metric for measuring the impact on the system. TURN and the IOUs opposed this due to cost-shift concerns and the ease of administration (otherwise, there may be disputes related to hourly production profiles). Another proposal (1b) proposed to extend this exemption to all projects by deleting "NEM" from the tariff proposal because the focus should be on electric impacts, but this was again opposed by TURN and the IOUs due to cost allocation principles. The IOUs also indicated that non-export, non-NEM generators are generally using synchronous machines and contended that energy storage inverters have less contribution to short circuit duty capabilities, though storage contributes more short circuit duty than solar. 

The second proposal reached consensus and recommended creating a soft link within Screen Q to the CAISO tariff by referencing Appendix Y and DD in the Rule 21 tariff. With an updated reference to Appendix DD of the CAISO tariff, the determination of electrical independence will be performed against Reliability Network Upgrades only versus Reliability and Deliverability Network Upgrades. Projects applying under Rule 21 are assumed to be seeking "energy only" status and thus are not subject to responsibility for Deliverability Network Updates, which this proposal aims to solidify.

The third proposal was to direct the IOUs to identify engineering review guidelines related to the evaluation, where there was consensus support for the proposal. The IOUs provided the following guidelines for engineering review in the EIT test results: (1) list all generation projects in the current queue that are adjacent to proposed project; (2) if current base-case is not complete, use last approved cluster base-case; (3) if a cluster is ongoing, with RNUs not yet finalized, compare pre-project base-case and post-project base-case loading when necessary to determine if there are any potential Network Upgrades required; (4) if a cluster is ongoing, with RNUs finalized, compare pre-project base-case and post-project base-case with RNUs considered and determine if the subject interconnection request triggers a change in scope for that RNU; and (5) consult with the CAISO as necessary. 

Finally, the fourth proposal was to create a venue to discuss a cost cap for qualifying DERs (based on proportionate share of reliability upgrades) that fail Screen Q to proceed despite transmission interdependence, which was opposed by TURN, ORA, and the IOUs due to lack of data on whether this is a reasonable request and due to potential for ratepayers to cover the remaining upgrade costs. GPI proposed that NEM and non-NEM projects less than or equal to 5 MVA that fail Screen Q should be given this additional option. This threshold was recommended because that is the limit for lower-cost interconnection studies under the Rule 21 Independent Study Process. 

On June 19, 2018, a workshop was held to provide an overview of Working Group #1 proposals (Issues #1-5 and #7) from the IOUs and other stakeholders, including CESA on Issue #2, for the benefit of Administrative Law Judge (ALJ) Kelly Hymes to understand the issues. The ALJ sought to specifically understand why the Screen Q exemption should not be extended to all non-exporting projects (Proposal 1b) and how NEM projects are different in terms of transmission grid impact. IREC contended that a balance is needed because there is no basis, for example, to allow a 1-MW exporting NEM system to be exempt from Screen Q but to not extend that same exemption to a 0.5-MW non-exporting project from bypassing Screen Q. The IOUs argued that there is insufficient record at this time to extend the exemption to non-exporting, non-NEM projects and that cost allocation would be complicated. PG&E clarified that cost allocation for transmission upgrades follow the CAISO tariff but that the upgrade costs for NEM projects are ratebased. The IOUs also indicated that inverter controls can stop continuous export but are not “fast enough” to provide short circuit duty (i.e., stop export into a fault).

On February 22, 2019, a PD was issued that landed favorably for members by exempting larger projects from a transmission study related screen. CESA commented that a process should be outlined and directed to modify the existing Screen Q exemption threshold based on net export upon approval of the certification standard, and that the certification standard for actively limiting export should not also have to limit fault current contribution.

See CESA’s comments on March 14, 2019 on the Proposed Decision

On April 5, 2019, D.19-03-013 was issued that PD approved expanding the existing Screen Q exemption for NEM facilities with net export less than or equal to 500 kW by increasing the exemption size threshold to all NEM and inverter-based non-NEM projects with 1 MVA or less nameplate capacity (Proposal 1a and 1b) and rejected IREC’s alternative based on net export due to the lack of certification to limited export, though it may be revisited upon adoption of certification schemes. For Proposal 1b, the CPUC found it appropriate to focus on electrical impact instead of program enrollment (e.g., NEM). In addition, the decision approved the soft link within Screen Q to the CAISO tariff’s Appendix Y and Appendix DD (Proposal 2), directed the IOUs to identify engineering review guidelines related to the evaluation of Screen Q (Proposal 3), and rejected creating a venue to discuss cost caps for qualifying DERs (Proposal 4) since costs exceeding the cap would be borne by ratepayers. The determinations made in the PD represent an important win for CESA members, as the Transmission Cluster Study Process can add one to two years to a project’s construction time. Given that very few projects (not exempt from Screen Q) have failed that screen, the decision appropriately determined there is an ample margin to raise the Screen Q exemption threshold without triggering transmission upgrades and while maintaining grid safety and reliability.

Proposal Implementation

On June 4, 2019, each of the IOUs submitted advice letters. PAO protested SDG&E’s advice letter for not proposing specific edits in their Rule 21 tariffs to implement Proposals 1A and 1B, where SDG&E instead proposed to implement the proposals via a website update in process. SDG&E changed it back.

Complex Metering Options (Issue #2)

Background

Currently, no clear framework or pathway exists for metering DC-coupled systems to connect through Rule 21 or NEM tariffs, which does not offer a fair, technology agnostic environment. Solar and energy storage companies believe that the lack of a clear definition of when complex metering is required is problematic and has led to excessive charges. CESA thus seeks to develop a clear delineation between configurations requiring simple metering and complex metering. CESA therefore proposed the following solutions to ensure NEM integrity:

• No grid exporting of energy storage through software controls as a means for DC-coupled systems to interconnect (with inadvertent export allowed)

• No grid charging of energy storage through software controls as a means for DC-coupled systems to interconnect

• Sizing of DC-coupled systems based on the lesser of the inverter nameplate capacity or the continuous output of the energy storage system

• Clarify NEM-eligible energy definition to allow appropriate metering proposals

• Allow DC metering arrangements to be allowed as DC meters establish the relevant standards

• Publication of indicative meter costs and arrangements to inform market participants

Proposal Development

On November 9, 2017, CESA provided an overview of this issue at an in-person Working Group meeting while the IOUs presented on examples that require standard versus complex metering installations. The IOUs said metering arrangements are determined on a case-by-case basis, but they confirmed that self-contained meters have an amperage limit of 200A so 24/48 kW (120/240 V) single phase or up to approximately 150 kW three phase (depending on configuration). Anything above that limit will need CT metering, which is considered complex metering. CESA and the IOUs reached consensus on the non-export option through controls and the non-charging through controls. CESA also raised the issue of third-party metering to avoid duplicative IOU meters. The IOUs seemed open to this in concept if the inverter or third-party meter can be verified. They have concerns around certification pathways, getting data into utility billing systems, and being able to maintain and test non-utility owned meters. Lastly, CESA raised the multi-metered premise challenge, but the IOUs are pushing for this issue to be out of scope.

On December 1, 2017, a revised proposal was prepared by CESA and circulated with the Working Group. Consensus was reached on three proposals to address the issue of the lack of clarity on complex metering options:

• The IOUs will develop illustrative metering configurations and cost tables to provide more transparency in the application of complex metering solutions.

• The IOUs will post information on their websites clarifying workable configurations of non-export relays for DC-coupled solar-plus-storage systems to protect NEM integrity.

• The IOUs will support development of DC metering standards by participating in the EMerge Alliance initiative.

CESA continues to work with members and the IOUs to allow for options with the equivalent function as a non-export relay (e.g., inverter controls) since such options are allowed under Rule 21 Section Mm. The approach where all discharge is prevented may be overly restrictive, as the energy storage system could be used to offset some of the onsite load as the NEM generator is producing.

On March 15, 2018, three consensus proposals were included to clarify the definition of complex metering solutions. The first proposal directs the IOUs to develop illustrative metering configurations and cost tables to provide more transparency in the application of complex metering solutions. The second proposal directs the IOUs to post information on their websites clarifying requirements for non-export relays and controls for NEM-paired storage systems to maintain NEM integrity. The third proposal supported the development of DC metering standards by having the IOUs participate in the EMerge Alliance Initiative or the equivalent. Overall, due to the potential for TOU arbitrage from energy storage capable of charging from the grid, the final report determined that there is no need for the CPUC to further clarify standard versus complex metering. CESA thus focused on getting the IOUs to clarify when and how controls can be used in lieu of metering. CESA strongly supported the consensus proposal that inverter controls can be utilized to maintain NEM integrity, especially given that the IOUs stated that non-certified control schemes can be reviewed, approved if compliant with IOU requirements, and validated via commissioning if deemed necessary.

On June 19, 2018, a workshop was held to provide an overview of Working Group #1 proposals (Issues #1-5 and #7) from the IOUs and other stakeholders, including CESA on Issue #2, for the benefit of Administrative Law Judge (ALJ) Kelly Hymes to understand the issues. CESA presented on the consensus proposals on this issue, but the ALJ sought to understand how much urgency there is in getting these issues resolved through a Ruling or Decision given the contentiousness of many of the other issues in this working group. CESA reiterated its views on the urgency of this matter, especially around the ongoing, active work in the eMerge Alliance to develop DC metering standards, which the IOUs committed to participating in.

On February 22, 2019, a PD was issued that landed favorably for members by clarifying complex metering and controls options for NEM-paired storage systems. CESA commented that the proposals to clarify costs, configurations, and requirements for NEM-paired storage interconnections will increase transparency but urgency is needed in developing DC metering standards.

See CESA’s comments on March 14, 2019 on the Proposed Decision

On April 5, 2019, D.19-03-013 was issued that approved all three proposals regarding this issue. The decision required the IOUs to develop illustrative metering configurations and cost tables to provide more transparency in the application of complex metering solutions, post information on their websites clarifying requirements for non-export relays and controls for solar-plus-storage systems to maintain CPUC-required NEM integrity requirements, and support development of DC metering standards by participating in the EMerge Alliance initiative or equivalent as IOU resources allow. Collectively, the decision found that the proposals would increase transparency and lead to more technology-agnostic rules.

Material Modification Definition (Issue #3)

Background

CESA was tasked with leading Issue #3 to clarify material modifications definitions in order to provide a clear and consistent pathway for modifying DER installations in interconnection applications and to existing facilities with Permission to Operator (PTO) - e.g., maintenance, retrofit. The definition should be reflective of the impact on the grid to ensure appropriate additional checks are only carried out where there is a benefit. A framework with appropriate thresholds can facilitate nonmaterial modifications with reduced burden, time and cost impacts. Specifically, CESA advocated for energy storage retrofits to PV installations that do not add to the site’s peak load, such as defined as Operational Mode 2 in Rule 21, to not be subject to material modification processes. CESA aimed to demonstrate that the level of export or charge to and from the grid is the factor that determines the impact on the distribution system. For example, a 5-kW solar system can have an energy storage system added without complication and significant reassessment, provided the maximum export does not increase above the previously approved 5kW limit at any one time. This can be achieved through the use of a partial export limiter or inverter programming controls.

On November 30, 2017, CESA led a discussion on this issue and is seeking to develop a standard definition for material modification with appropriate thresholds. The IOUs have been working to identify which modifications may be allowed without requiring re-application, including identifying illustrative examples to support transparency on this process. Notably, the IOUs stressed that “materiality” also depends on how a modification impacts other DERs downstream in the queue. There are open questions related to the definition of “equivalence” when it comes to equipment replacement. For energy storage systems, equivalency is defined having the same or lower kWh rating and same operating profile for Fast Track applicants to maintain their queue position. Adding a new energy storage system, however, is considered an increase in capacity of an existing generating facility and would require a new application, according to the IOUs. The IOUs noted that there are currently no Rule 21 procedures directly governing how project modifications are addressed after an Interconnection Agreement is executed.

Proposal Development

On January 11, 2018, CESA submitted a draft proposal that covered material modifications in the application process. The proposal detailed how modifications for “like for like” equipment size or capacity reduction (up to 10% maximum) to an application allows it to maintain its queue position and proceed through the interconnection process. If upgrades or mitigations are identified, the queue position can be upheld so long as the customer is willing to pay for those upgrades or mitigations. There was also consensus that modifications involving size or capacity increases, point of interconnection change, and change of operational profile of the energy storage system would not be allowed under Fast Track for all projects.

On February 13, 2018, CESA shared its draft proposal that outlined maintenance and retrofit use cases. When replacing equipment with the exact same equipment (i.e., same make and model), CESA achieved consensus with the IOUs that no notification would be required. When replacing “like for like” equipment where the size of the equipment does not exceed what is listed in the interconnection agreement, CESA proposed that only notification (no application) is needed. The IOUs, however, propose an abridged application with no engineering review due to their need to validate certain equipment and grandfathering provisions, as well as a potential legal obligation to update interconnection agreements. CESA also proposed a notification-only process for two use cases where: (1) replacement equipment does not exceed 10% above the DER “limiting factor” listed in the interconnection agreement; and (2) added or replacement equipment exceeds this limiting factor but has firmware controls that limit the “effective increase” in the interconnection agreement. Again, the IOUs expressed concerns about the legal obligations, impacts on grandfathering provisions, impacts of 10% increases on potentially overloaded circuits, and processes for validating software controls. The IOUs are still developing their feedback and potential counterproposals to CESA’s ideas on how retrofit use cases should be treated in the interconnection process.

On March 15, 2018, there were three consensus proposals around the core definitions of material modifications, but there was little agreement around the process options – e.g., no notification, notification only, streamlined interconnection request, and normal interconnection request. For the first proposal, there were three modifications proposed around the definition of material modifications to interconnection applications. While "non-material" definitions are in place for the Detailed Study process, it is not specified in the Fast Track process. ‘Like-for-like’ replacements were defined as equipment replacements that do not increase facility size, does not exceed 20% for size decreases, and does not identify upgrades or mitigations needed. 

• For inverters, 'like-for-like' means certified, same nameplate or smaller, same fault current or smaller.

• For solar panels, 'like-for-like' means certified, same CEC-AC rating of the system or smaller.

• For battery storage, 'like-for-like' means same or less kWh and kW rating and same operating profile.

• For transformers, 'like-for-like' means same connection type, same or smaller impedance and capacity.

Size reductions were defined as not exceeding 20%, with customer paying for any identified upgrades or mitigations. Note that system 'size' is defined as the limiting factor that determines the maximum generating facility capacity. 

• For solar panels, the limiting factor is the lesser of inverter nameplate capacity (kW) or maximum solar output (CEC-AC rating).

• For battery storage, size is defined by the inverter nameplate capacity (kW) and the capacity of the storage device (kWh) - the IOUs note the importance of kW to determine whether electric system can handle its maximum capacity while kWh is important from a capacity and modeling perspective.

• For all other generation types, the limiting factor is the gross nameplate rating of the generator.

For size reductions to avoid upgrades, the customer agrees to pay a $300 fee for the IOU to conduct a re-study to validate that no other DERs are impacted. Furthermore, in addition to the above changes, the working group proposed to only for only one modification request per interconnection request, a $300 re-study fee for size reductions to avoid upgrades, a processing time of 10 business days for all modification types (and an additional 20 business days for engineering re-study time, if needed), and maintaining cost responsibility requirements of original size for size reduction modification requests. 

Overall, the three consensus proposals for modifications of interconnection applications while maintaining interconnection queue position will be important for time and cost certainty for DER interconnections. These proposals will also provide flexibility to swap make/model of equipment (but not the rated output) in case of original equipment unavailability and allow for downsizing of systems to avoid unforeseen upgrades - all factors that may be outside of the customer's control. While supportive of the modifications, the IOUs did comment that these changes may affect Fast Track timelines, financial securities (to only allow this for 'serious' projects), and study fees (for re-performing reviews). 

The disagreement among stakeholders came around the process options for the use cases considered for existing facilities with PTO. The IOUs also noted that they do not have processes in place for a notification-only or an abridged interconnection request - i.e., their interconnection portals would likely need to be modified to support Process Options 2 and 3. The IOUs consider the implementation costs to be too high relative to the added benefit, given the low volume of such requests to date.

• Process Option 1: No notifications is required: No requirement to amend an existing interconnection agreement, no engineering review is required, no program check required, and no need to update records.

• Process Option 2: Notification is required: Customer can proceed with building the system and turning on the system upon notification without waiting for IOU approval. Customer may be required to complete a form listing the changes. No engineering review is required, but administrative confirmation, program check, and record updates of changes will be required. IOU must receive electric release in notification if permit is required by AHJ.

• Process Option 3: Abridged/streamlined interconnection: Customer must wait for IOU approval to turn on the system but engineering review is not required. New "abridged" interconnection request must be submitted, and all other details of Process Option 2 apply here.

• Process Option 4: Interconnection request: Customer must wait for IOU approval to turn on the system and engineering review is required. All other details of Process Option 2/3 apply here.

Other than SDG&E, there was clear consensus on Use Case 1 that no notification is required for regular maintenance work of replacing parts, though the IOUs generally agreed that accurate records may still be needed and local jurisdictions and NEC codes must still be adhered to. CESA, along with other non-IOU stakeholders, advocated for a notification-only process when replacing equipment ‘like-for-like’ while not increasing system output by employing firmware controls, or when adding energy storage capacity (kWh) without changing the inverter. However, the IOUs found that streamlined interconnection would still be needed. The only area of majority agreement was around the use case where equipment is being replaced with the exact same make and model that do not affect the grid, where all stakeholders except SDG&E agreed that no notification is required. In addition, all stakeholders generally agreed that a full interconnection request is needed when adding storage to a standalone generator, increasing system capacity without controls limiting output, and changing inverter settings.

On June 19, 2018, a workshop was held to provide an overview of Working Group #1 proposals (Issues #1-5 and #7) from the IOUs and other stakeholders, including CESA on Issue #2, for the benefit of Administrative Law Judge (ALJ) Kelly Hymes to understand the issues. The ALJ was walked through each use case to understand the rationale for the different interconnection review level needed. The IOUs generally commented that some time (2-3 years) is needed to implement the tools to accommodate certain modification processes for changes in panels and inverters. In the case for ‘like-for-like’ inverter replacements, CALSSA discussed how these modifications should be viewed as typical O&M and should not require additional review or documentation, such as from the local building department. SCE shared this view because they view this as a “beyond the meter” issue. However, SDG&E shared its view that documentation and field visits are still needed for such replacements to ensure the inverter is certified. In the other use cases, the IOUs generally expressed their view that certification of inverter control systems are needed, making notification-only processes untenable.

On February 22, 2019, a PD was issued that landed favorably for members by clarifying complex metering and controls options for NEM-paired storage systems. CESA commented that the material modification process proposals require several key modifications and clarifications, such as by reassessing the 100-kW threshold to be based on relative change.

See CESA’s comments on March 14, 2019 on the Proposed Decision

On April 5, 2019, D.19-03-013 was issued that made a number of determinations. It adopted material modification definitions for like-for-like equipment replacements, size reductions, and size reductions to avoid upgrades, limited to one the number of modifications per request (which can contain multiple modifications), did not require additional fees for modification requests except in case of size reduction to avoid upgrades ($300 re-study fee) and established timeline of 10 business days to process modification request or 20 business days for requests requiring re-study. Overall, the decision found it reasonable to grant developers additional flexibility without losing queue position. However, the decision rejected CALSSA’s proposal to limit processing time to five business days, given the same time is needed for new or modified requests. Furthermore, the decision approved new process options for different use cases for material modification as follows:

The decision had some minor modifications and clarifications relative to the PD. For use case 1, the decision disagreed with SDG&E that notification to the utility is required since ensuring that permits are issued from AHJs are not the responsibility of the utility.  Furthermore, the decision was modified from the PD in that projects above 100 kW could use process option 2 as long as systems increase to 110% of their original generating facility capacity as identified in its original permission to operate, which is in line with NEM grandfather language, and as long as inverter power controls are used to maintain the original permission to operate real power output. Previously, in the PD, all projects above 100 kW would have been subject to process option 4.

Proposal Implementation

On July 5, 2019, joint IOU advice letters were submitted that described the standard form template (i.e., notification worksheet) for Process Option 2 for material modification processes to be used as an interim solution while the IOUs independently develop a more permanent solution. CALSSA submitted a protest that the IOU’s proposed form include an additional questions asking whether the nameplate capacity of the replacement inverter is within 110% of the nameplate capacity of the previous inverter while using advanced inverter functionality to limit the output to the capacity approved in the existing interconnection agreement, under which customers would be able to use the notification-only material modification process. Importantly, CALSSA commented that the “110% rule” should apply to projects of any size.

PG&E and SDG&E agreed to the clarification in its response but also recommended that the CPUC provide clarifications of the process option that would apply according to whether the system is greater or less than 100 kW and whether the modification is greater than or less than 110% of the original capacity. Meanwhile, SCE provided specific recommendations to clarify the “110% rule” as follows:

• For all projects increasing capacity at or below 100 kW, notification is required.

• For all projects increasing capacity to above 100 kW, a new interconnection is required.

• For projects of any size requesting to increase capacity within 110% of its original generating capacity and more than 100 kW, a new interconnection is required.

On July 23, 2020, an Order was issued correcting an error in D.19-03-013 where, for Use Case 3, the CPUC should adopt Process Option 2 for projects increasing to below 100 kW, following the creation of certification schemes to limit export to the original generating facility’s nameplate capacity, and Process Option 4 for projects increasing capacity to at or above 100 kW and more than 110% of the original generating facility’s nameplate capacity. This correction would align with the other sections of the decision.

Telemetry Requirements (Issue #4)

Background

As the penetration of DERs has grown, the IOUs have raised the issue of whether Rule 21 Section C should be revised for transmitting real-time metering data to the IOU through telemetry.

Proposal Development

The IOUs seek to reduce the threshold for requiring telemetry from projects with capacity of 1 MW to 250 kW to provide it greater visibility and situational awareness of DERs under 1 MW. The IOUs highlight how individual project impacts, in aggregate, add to significant amount of generation at the circuit level, which requires the IOUs to have greater visibility of DER to know when to switch the distribution system for planned and unplanned conditions. On average, approximately 250 applications per year are greater than 250 kW, according to IOU numbers in recent years.

This is a major concern for members and was a non-consensus item in the working group. The costs of telemetry requirements were especially a concern. For example, PG&E charges $100,000 for telemetry because they lack a good communication solution. The other IOUs have a better communication solution that only costs applicants $5,000 to $10,000 to meet telemetry requirements.  Instead, CESA sought to establish $10,000 cost caps for systems above 1 MW and up to 10 MW. A potential outcome of this working group efforts will be that costs for 1 MW and greater systems will come down while the costs for 250 kW to 1 MW systems will see a small additional (capped) increase.

The non-IOU stakeholders have countered with a proposal that maintains the 1-MW threshold for requiring telemetry (based on the maximum facility export in the interconnection agreement) and instead recommends that the IOUs involve customer-owned data acquisition systems connected to the IOU Energy Management System to deliver telemetry information. They argued that measurements do not have to be made from revenue-grade equipment since the telemetry data is used for operational and planning purposes only.

On March 15, 2018, a final report was issued. The CAISO’s comments on the report were notable because, even though they did not endorse or oppose any specific proposal, the CAISO indicated that it needs some visibility on DERs below 1 MW for short-term forecasting purposes and even suggested a sampling approach to gain this visibility.

On June 19, 2018, a workshop was held to provide an overview of Working Group #1 proposals (Issues #1-5 and #7) from the IOUs and other stakeholders, including CESA on Issue #2, for the benefit of Administrative Law Judge (ALJ) Kelly Hymes to understand the issues. With telemetry requirements not updated in 15 years, the IOUs presented their proposal to reduce the threshold for generating facilities to have telemetry to provide real-time data since current 15-minute meter data is insufficient for real-time reliability operations. The ALJ sought to understand why telemetry costs have come down for SCE but why this has not been the case for PG&E and SDG&E. CALSSA discussed how smart inverter communication requirements may obviate the need for these new telemetry requirements, while the IOUs discussed how this is necessary, already being done in Hawaii (via Rule 14H), and would impact only about 45 additional projects.

On February 22, 2019, a PD was issued that landed favorably for members by clarifying complex metering and controls options for NEM-paired storage systems. CESA commented that further stakeholder review for the proposal to lower the telemetry threshold is prudent but this evaluation should also broadly assess all potential cost-effective options.

See CESA’s comments on March 14, 2019 on the Proposed Decision

On April 5, 2019, D.19-03-013 was issued that punted on making a determination on this issue and instead directed a workshop to be held within 90 days of the decision (Summer 2019) to determine whether the IOUs’ proposal to lower the telemetry requirement threshold from 1 MW to 250 kW if the estimated utility-related costs are less than $20,000 (Proposal 1) is cost-effective. The IOUs are also directed to file advice letters on specific technical requirements and associated cost-benefit analysis, including on alternatives such as smart inverter and/or SCADA data. However, the decision approved the proposal to allow customer ownership of BTM telemetry equipment (Proposal 5), which also established a cap of 30 days to repair or replace malfunctioning equipment as notified by the utility and if the malfunctioning equipment is replaced by 30 days. The decision found the customer ownership option as a way to mitigate the costs associated with utility ownership of the equipment.

Proposal Implementation

On June 26, 2019, a workshop was held to discuss the IOUs’ existing, proposed, and alternate telemetry methods and approaches that addresses the load masking condition (real-time production data), costs less than $20,000, and provides other comparative information such as the “non-utility” communication costs with DER communication companies. The IOUs discussed how the telemetry solution drivers should focus on grid operation needs, customer costs, cybersecurity, and future orientation.

On July 26, 2019, each of the IOUs submitted their proposals on telemetry requirements. They generally agreed that the use of SCADA devices did not meet the low-cost target of $20,000, costing approximately $70,000 to $160,000 per customer in the case of PG&E, and would only measure the net output of a generating facility (not the load-masking condition). Using AMI metering, meanwhile, would not meet the operational requirements due to only measuring net load, slow data sampling rates, and slow data retrieval rates. Finally, each of the IOUs dismissed the use of smart inverters as a telemetry option (unless connected to a communication network via the appropriate protocols) because they are not connected securely and reliably in real-time manner to the IOUs’ systems, require additional equipment, require the aggregation of data to facility-level rather than for individual inverters, and are not required as a Phase 3 function at the moment.

Instead, each of the IOUs proposed a communication solution using the IEEE 2030.5 protocol for smart inverters to identify masked load effects and create a near real-time system integrated with IOU operations. Importantly, this telemetry option would ensure cybersecurity requirements are met. CALSSA, IREC, and PAO submitted protests on August 15. CALSSA and IREC generally commented on how the IOUs have inadequately justified the real-time operational costs of load masking while IREC said that the IOUs have not sufficiently explored whether AMI can be used to collect data in more frequent intervals (i.e., 15 seconds instead of 15 minutes) to capture load masking information, given the state has invested heavily in AMI infrastructure thus far. PAO also requested more information on cost verification and funding sources for SCADA devices.

• PG&E proposed a pilot through 2020 to deploy telemetry infrastructure at locations requiring telemetry already and to enable design around the future IEEE 2030.5 DER communications standard for a limited number of sites using the DER Headend platform. Until the lower-cost telemetry solution has been deployed, PG&E plans to retain the 1-MW threshold and assess each project greater than 1 MW on a project-by-project basis to determine if telemetry alternatives could be used. In the long term, PG&E said it will explore both monitor and control capabilities (e.g., adjust polling rate). CALSSA requested that the technical requirements of the pilot be specified and generally commented on the ability of aggregators to conduct the IEEE 2030.5 function without a physical box or secured virtual private network.

• SCE presented on using the current solution of an internet-based centralized RTU and issuing a conditional permission to operate (PTO) until a longer-term solution is developed. SCE introduced a telemetry concept involving a DER cloud provider (e.g., Verizon, AT&T) and generating facility communication equipment (i.e., remote telemetry device at $5,000 one-time cost) via the IEEE 2030.5 protocol 2022. However, SCE could not determine an accurate cost, which depends on the non-utility communication costs. IREC commented that more information is needed on SCE’s proposed private network approach as cost-effective, since there would be no choice for DERs to select cellular providers, other than the one chosen by SCE. CALSSA appreciated SCE’s change in approach to rely on IEEE 2030.5 but protested SCE disallowing the use of an aggregator’s own cloud communications even if it meets cybersecurity specifications.

• SDG&E did not recommend an interim telemetry requirement, instead supporting the imminent implementation of IEEE 2030.5 and only requiring a separate internet-connected customer-owned equipment for all DERs above 1 MW, costing around $2,500 each. IREC supported SDG&E’s internet-based telemetry approach as having potential as a cost-effective solution, but more information is needed. CALSSA’s protest focused on how SDG&E intends to explore telemetry options for DERs between 250 kW and 1 MW after IEEE 2030.5 has gone into effect.

Overall, the IOUs’ approaches in the short term involve no major changes, especially for DERs between 250 kW and 1 MW, but in the long-term, they commonly envision utilizing Phase 2 communication requirements (IEEE 2030.5), which will be required anyways by January 22, 2020, and expanding the requirements to all DER sizes. However, such solutions may entail unspecified "non-utility" communication costs for DER providers and integration with third-party DER communication providers – a potential non-starter for aggregators. These costs are unclear and represents one area of potential concern but represents an improvement over other hardware-based telemetry options that could cost several tens of thousands of dollars. The IOUs also generally responded to IREC’s and CALSSA’s concerns about the justifications for other telemetry options, noting that SCADA, AMI, and IEEE 2030.5 only provides data on the net output of the generating facility, not in conjunction with customer load data, and thus does not provide information on load masking. AMI is also used for billing in 15-minute intervals and is batched once per day, making it insufficient for real-time operations, according to the IOUs.

Smart Inverter Phase 1 Function Retrofitting (Issue #5)

Background

The Rule 21 Working Group #1 is considering whether to activate advanced functionality in Phase 1 compliant inverters installed before September 9, 2017 (Issue #5). Starting on September 9, all inverter-based generation interconnecting under Rule 21 were required to provide Phase 1 autonomous inverter functionality pursuant to D.14-12-015, but by extending this functionality to existing inverters, the Working Group must identify the reasons and safety/reliability risks and quantify the benefits of making legacy systems compliant with Phase 1 functionality.

On December 7, 2017, a teleconference call was held to discuss a framing document, where Enphase shared their experiences with a similar type of retrofit strategy in Hawaii. Hawaiian Electric (HECO) and Enphase discussed how the high level of renewables penetration on Oahu led to potential risks of a single large generating unit creating frequency stability issues. Under Rule 14h, HECO asserted its authority to require updates to inverters interconnecting onto their system. After reaching out to stakeholders, HECO determined that it would prioritize frequency ride-through among the Phase 1 functionalities because most installed capacity could only be retrofitted for select functionalities without violating the UL listing. HECO also sought to minimize the cost of implementation by having inverters updated remotely over the Internet and worked with manufacturers and system integrators to update their systems. Enphase also highlighted HECO’s experience in working through legal issues, where the customer must approve the change whenever there is a change in energy. HECO employed opt-out methods and aggregated information to protect customer privacy. With the HECO experience as lessons learned, the CPUC led a discussion on how a similar retrofit strategy could be implemented in California for its installed capacity of inverters. The challenge for California is that there is a broader range of products and manufacturers (unlike Hawaii where Enphase has a significant share of the residential market) and the current Rule 21 does not require updates to those systems (like it does for Rule 14h in Hawaii). Developers on the call were asked to identify how many of their legacy systems could comply with this type of requirement, but many of them pushed back and argued that it may be more cost-effective to wait for the replacement of existing inverters rather than retrofitting them.

On January 18, 2018, the CPUC and IOUs shared their findings after taking an inventory of existing inverters and the group discussed potential orders of priority based on size and cost-effectiveness of each group. Eight inverter companies, representing 81% of California’s market share, responded to a survey that found that less than 5% of inverter capacity can be updated remotely via software update or through non-certified firmware updates. The costs of this remote update as reported by survey respondents were estimated to be approximately $1-2/kW. Yet still, there may be barriers to receiving customer consent to revise interconnection agreements.

Proposal Development

On January 31, 2018, four competing proposals were submitted on by the IOUs, CALSEIA, Enphase, and ABB. There is consensus behind a proposal to not establish a retrofit program due to the small percentage of systems that can be updated to all seven functions (i.e., costs do not justify the scale of benefits) as well as for a proposal that would encourage, but not require, replacing end-of-life inverters with smart inverters because it supports the IOUs’ objective to convert all inverters to smart inverters and industry’s concerns about requiring smart inverter replacements where it is physically or legally not feasible. The IOUs do not support the proposal to only activate only some of the Phase 1 functions (e.g., ride-through) given the same issue where costs outweigh the benefits, while industry does not support the proposal to make replacing end-of-life inverters with smart inverters the default option because of sizing and physical space constraints, electrical incompatibility with solar systems, or warranty voidance issues.

On March 15, 2018, two consensus proposals were included that recommended that (1) the CPUC should neither require nor incentivize activation of Phase 1 functionalities and (2) the CPUC should continue to allow (and encourage but not require) customers to replace existing inverters with inverters of “equal or greater ability”. These rationale for these proposals were based on the administrative and cost burden as well as the legal issues around customer consent of retrofitting existing inverters, which most stakeholder believed could soon become compliant with Phase 1 functionality once these inverters will need to be replaced. Unlike the HECO case, stakeholders also noted that the market is fragmented by inverter manufacturers. However, the non-consensus proposal was around modifying Rule 21 to require customers to replace existing inverters with smart inverters at end of life, which was opposed by most non-IOU stakeholders.

On April 5, 2019, D.19-03-013 was issued that approved the proposal to neither require nor incentivize activation of advanced functionality in Phase 1-compliant inverters installed before September 9, 2017. Customers are allowed to replace existing inverters with inverters of equal or greater ability, pursuant to D.14-12-035, and will be encouraged, but not required, to replace existing inverters with smart inverters at end of life.

Income Tax Component of Contribution (ITCC) Charges (Issue #7)

In June 2016, the IRS issued Notice 2016-36 that updated the safe harbor regarding transfers of property from an electricity generator to a regulated public utility to reflect industry changes. Namely, the Notice recognized that T&D systems have evolved and allowed cross-regional payments and transfers for transmission upgrades and new connecting transmission facilities to qualify for non-taxable contributions in aid of construction (CIAC) under safe harbor provisions, which would apply to transfers from energy storage facilities to utilities as well. The Notice removes the requirement for a long-term power purchase contract or a long-term interconnection agreement to qualify for safe harbor.

On January 26, 2018, a working group meeting was held where the IOUs informed that the actual ITCC audits or denials related to claimed safe harbor status have not been assessed in recent years, but the IOUs reiterated that they still maintain a concern about liability risk when there is a taxable event. Theoretically, the IOUs believed that it is possible that projects may be violating the 5% rule. PG&E and SDG&E clarified that they not usually require security while SCE usually does, which is intended to protect against the possibility that safe harbor classification may change. The risk of reclassification seemed to be unquantifiable, according to the IOUs, due to current IRS practice of not forcing the IOUs to audit and determine where it is appropriate to remove safe harbor. The IOUs sought to ensure that there is cost recovery when there is a taxable event. The IOUs believed it is up to the developer community on whether to seek IRS clarification on the eligibility of BTM generation for ITCC safe harbor. 

On February 13, 2018, three proposals were developed by the working group – none of which had consensus support. The IOUs supported the Proposal #1 (Status Quo) and supported Proposal #2 (All Collect), which directed the IOUs to all collect the ITCC security for safe harbor projects to ensure consistency across the IOUs, if the Proposal #1 is unavailable. Unsurprisingly, the non-IOU stakeholders did not support either of those proposals; rather, they supported Proposal #3 (Prohibit ITCC Security Collection), which would instead authorize a recovery mechanism borne by ratepayers to make the IOUs whole should projects lose its safe harbor eligibility status.

Working Group 2

Background

WG 2 began meeting on March 15, 2018 and submitted a final report on October 31, 2018 on the following issues:

• How should the Commission incorporate the results of the ICA into Rule 21 to inform interconnection siting decisions, streamline the Fast Track process for projects that are proposed below the integration capacity at a particular point on the system, and facilitate interconnection process automation? (Item 8)

• What conditions of operations should the Commission adopt in interconnection applications and agreements to allow DERs to perform within existing hosting capacity constraints and avoid triggering upgrades? (Item 9)

• How can the CPUC coordinate the ICA and Rule 21 processes with the Rule 2, Rule 15, and Rule 16 processes in order to improve efficiency of the overall interconnection process? (Item 10)

• Should the CPUC adopt a notification-based approach in lieu of an interconnection application for non-exporting storage systems that have a negligible impact on the distribution system? If so, what should the approach entail? (Item 11)

On October 31, 2018, the Working Group #2 Final Report was filed and a workshop was held on November 7, 2018 to present the final report on issues #6-#11 to the ALJ.

On December 7, 2018, a Ruling was issued seeking comment on the final proposals, which included a major set of proposals to streamline Rule 21 interconnection using ICA values developed by each of the IOUs (e.g., bypass of certain screens). The focus of those proposals was on fixed generation resources such as solar, but there may be future iterations of this proposal for dispatchable resources like energy storage. In addition, there were other relevant proposals related to building off the Section N expedited interconnection pilot process to develop a new ‘NEM-like’ Lighting Review process, and a non-consensus proposal for a DER agreement to meet the Phase 2 smart inverter communication requirement for aggregators. Each of these proposals have potential implications for the interconnection and operations of energy storage systems, so it will be important to shape these technical requirements to reduce/address these barriers.

CESA provided the industry and developer perspective on why it is important to address some key threshold questions before adopting a DER aggregator agreement, recommended future consideration of how the ICA can be used to streamline energy storage interconnections, and provided a public policy rationale for supporting a Lightning Review process for non-exporting energy storage systems. Notably, TURN focused on the need to evaluate the costs and benefits of the range of proposals, especially when considering whether any given proposal benefits or affects a small number of projects but require significant IT or tariff changes. PG&E also recommended against incorporating the ICA into Rule 21 prior to 2020 due to the need for engineering studies.

In our responses to other parties’ comments, CESA focused in on a problematic IOU proposal to subject non-exporting energy storage systems to a full Rule 21 review given reliability concerns of net load reduction on feeders with high solar penetration. We disagreed with this perspective and reiterated our views on customer’s right to manage load and how such customers should not have cost responsibility or be subject to interconnection delays due to upgrades needed for issues created by other DERs. If delays are needed, CESA made the case for a ‘make-whole’ payment to offset the costs of these delays for upgrades caused by other DERs. Multiple other parties (CALSSA, IREC, Tesla) also agreed with the principle, while the IOUs argued that it is impossible to know whether upgrades are needed on a proactive basis during the interconnection process without going through the additional review screens.

See CESA's comments and reply comments on February 1, 2019 and February 22, 2019

Rule 21 Agreements for DER Aggregators and Smart Inverters (Issue #6)

Background

A subgroup including the Smart Inverter Working Group (SIWG) and other members of Working Group #2 was formed to discuss and form proposals for Issue #6, which considers whether the CPUC should require the IOUs to develop forms and agreements to allow DER aggregators to fulfill Rule 21 requirements related to smart inverters.

Proposal Development

On June 20, 2018, stakeholders held a sub-group call to discuss the need to develop a proposed definition of “DER aggregator” and agreed that communication requirements and technical capabilities need to be identified and translated into necessary forms and agreements. Stakeholders, however, disagreed on whether the compensation of services should be discussed in this sub-group, as some identified the IDER proceeding as a more appropriate venue for those discussions. The CPUC agreed that compensation is out of scope due to the Rule 21 proceeding not being set as a ratemaking proceeding, and that some of these issues could be discussed in Issue #27 (Operationalizing Smart Inverter Functionality). Other in-scope issues include identifying communication and operational requirements, setting insurance requirements, and addressing customer privacy, cybersecurity, and legal concerns.

Tesla proposed that "DER aggregator" be defined as a non-utility entity that has the capability to monitor and communicate key data related to the state of inverters, pursuant to Phase 3 requirements, both individually and in aggregate, to the utility. The aggregator also must be capable of receiving commands and schedules from the utility and be capable of delivering those commands/schedules to the inverters. Alternatively, SCE proposed that an aggregator be defined as performing a role that would otherwise be performed by individual generating facilities (i.e., act as a conduit to send commands from the IOU to the generating facility and send information from the generating facility to the IOU). 

On July 11, 2018, a subgroup call followed up on defining “DER aggregator” and pointed to a number of definitions in place through utility DR programs, through the Wholesale Distribution Access Tariff (WDAT), and through the CAISO’s Distributed Energy Resource Provider (DERP) agreements that can be modified to add provisions around communication requirements, possibly leveraging the previous work completed in the SunSpec Alliance’s Common Smart Inverter Profile (CSIP) document as a source to identify common language (see IEEE 2030.5 implementation guide and conformance test procedures). Subgroup members generally agreed that an agreement between the utility and aggregator for each participating generating facility is needed, which could include a modification of existing interconnection agreements as an appendix or a standalone agreement between three parties (utility, generator, customer). Participants noted that the agreement must reflect differences in aggregators who conduct the interconnection process for the customer and aggregators who only perform the aggregation service and must accommodate changes to the designated aggregator. The IOUs recommended that the requirements in the agreement reflect effective cybersecurity and performance considerations, such as the impact of DER aggregations on the distribution grid.

On August 1, 2018, a sub-group call was held where SunSpec Alliance began with an overview of the technical communication capabilities of smart inverters and the potential relationship of those standards to DER aggregators under Rule 21. From the CSIP, the aggregator is assumed to be managing a fleet of inverters that are distributed across the utility’s service territory rather than having a single point of common coupling and thus the aggregators is responsible for relaying any requirements for DER operational changes or data requests to the affected systems and returning any required information to the utility. In managing business and security risks, there are questions about the solvency, competency, cost certainty, conflicts of interests, and operational continuity about the aggregator. Given this, SunSpec Alliance proposed a minimal dataset for qualifying aggregators, which, once finalized, will contribute to the development of aggregator forms and agreements under Rule 21.

The IOUs then proposed an update on the “DER aggregator” definition to include “an entity that provides the communication capability functions required in Section Hh on behalf of one or more Generating Facilities that utilize inverter-based technologies” – a definition that may impact the ability of an aggregator to fulfill service and performance obligations that are beyond the scope of Rule 21. Finally, the sub-group continued the discussion on example forms and agreements, which is still a work in progress but may use the CAISO DRP agreement and SCE’s LCR contract with Stem as a starting point.

On August 21, 2018, the sub-group discussed additions and/or edits to SunSpec Alliance’s minimal dataset. In particular, the IOUs expressed that the agreement must provide them with confidence that the system will not operate out of compliance with various requirements (e.g., performance, force majeure) if an aggregator disappears. It was proposed to give the customer a grace period to find another aggregator or establish a direct communication protocol with the IOU if the customer is stranded. SCE volunteered to create a proposal agreement for sub-group review, leveraging existing contracts, such as those from the CAISO.

On September 12, 2018, a conference call was held to discuss the draft aggregator agreement and how it should better account for software and/or cloud-based technologies, potentially through references to the architecture diagram used in the Common Smart Inverter Profile document. Specific areas that were identified as being needed to be addressed include physical testing, end-to-end testing, inspections, hardware performance testing requirements without testing every single generating facility, and addition and subtraction of ‘participating generation facilities’ in aggregations.

On October 31, 2018, the Working Group #2 Final Report was filed that included a draft agreement that would govern the terms and conditions under which a DER aggregator will provide communication functions, but this draft agreement was also recognized as incomplete and in development. "DER aggregator" was defined as "an entity that provides the communication capability functions required in Section Hh on behalf of one or more Generating Facilities that utilize inverter-based technologies. An Aggregator is intended to perform a role that would otherwise be performed by individual Generating Facilities. The Aggregator shall act as a conduit, sending commands from the Distribution Provider to a Generating Facility and sending information from a Generating Facility to a Distribution Provider." The IOUs specifically sought consistency of information being supplied to enable assessment of capabilities (e.g., communications, scheduling, performance), but storage providers commented on the need to clarify contract provisions (i.e., capabilities vs. utilization), whether the contract was open-ended, what the roles are (e.g., conduit vs. executor), and re-certification process as software changes. All parties generally agreed that the agreement governs capabilities, not actual performance. The IOUs highlighted the importance of this distinction as governance of actual performance runs the risk of conflicting with other program and tariff requirements. CALSSA expressed a different interpretation of the agreement, stating that the governance of capabilities is not needed in an agreement if it can be demonstrated through certification to a (to-be-developed) standard. Meanwhile, Tesla also cautioned that the current version of the agreement reads as going beyond requiring capabilities to requiring performance obligations.

On November 15, 2018, the SIWG held a conference call to discuss different software change scenarios. Stem presented on how unnecessary re-certification or conformance testing should be required when an aggregator goes through some software changes, explaining that the NRTL conducts CSIP testing for utility to aggregator communications and that the utility-aggregator agreement includes an ongoing compliance commitment (e.g., CSIP re-certification, utility performance testing, internal regression tests).

Streamlining Interconnection with ICA (Issue #8)

Background

On March 14, 2018, the kick-off meeting was held to have a preliminary discussion on the issues and to preview the proposed schedule, which will occur through regular remote and in-person working groups.

On April 4, 2018, the first in-person workshop was held that kicked off with SCE providing an introduction of the ICA. SCE initially proposed that the ICA may be able to replace Rule 21 Screens F, G, L, M, N, O, and P, though SCE and SDG&E believed that there may be an exception to Screen L, which is related to transmission and must be performed to determine when it is appropriate to remove Screen L. PG&E, however, discussed how Screens F, M, and N can be considered for streamlining using the ICA but stressed that Screens O and P require further discussion because the application of those screens can be application specific due to the details around the grounding and transformer configuration of the generating facility. PG&E also discussed how Screens G and L may be ineligible for these ICA discussions because “interrupting ability” is not considered in the current version of the ICA. SCE recommended that the ICA values be updated monthly. Overall, the IOUs appear to want to cautiously focus on screens that can be readily streamlined with the ICA and to potentially expand the number of screens that could be streamlined after further discussion and review and/or refinements to the ICA.

On April 6, 2018, a scoping memo prepared by Gridworks was circulated to delineate what questions are in and out of scope for discussion in this working group. Among the issues proposed as being out of scope include modifications of the ICA that are different than the approved methodology from D.17-09-026 as well as certain operational considerations that will be teed up for further discussion in Issue 9.

Proposal Development

On April 11, 2018, a working group meeting was held to start preliminary discussions on how ICA values line up with the Rule 21 screens. To begin, SCE introduced a set of guiding principles to serve as the basis for the current and subsequent working group discussions: (1) must account for the safety and reliability requirements of interconnecting DERs (i.e., no screens will be "ignored" or "assumed" to not have negative effects); (2) will maximize the information and results from the ICA calculations; and (3) minimize the effect of those screens that are not addressed by the ICA calculations to the extent possible. Due to (3), SCE proposed that Screens A-H, L, Q, and R would not be part of the scope here because these technical criteria is not part of the ICA. Conversely, SCE proposed that Screens M-P and the fast-track export limit is within the scope because these screens are considered as part of the ICA. As an illustrative example, SCE proposed the process below that would map the ICA values to the Rule 21 process.

On April 17, 2018, a working group call was held that provided additional clarity to the ICA and continued the preliminary discussions on Rule 21 screens. The IOUs clarified that the ICA reflects reverse power flow up to the low-side busbar and that any reverse power flow from the low-side to high-side busbar is represented with a zero ICA value, though projects could still potentially interconnect if they undergo full Rule 21 study. The IOUs added that Screen Q is not applicable in these cases. The working group progressed to discuss the Rule 21 screens that could be streamlined using the ICA. Previously, the IOUs generally agreed that Screens F, M, and N could be streamlined using the ICA but discussed how Screens G, L, O, and P requires further discussion or may be ineligible for the ICA. On this call, the working group focused on Screens F, G, and L, where it was generally discussed how projects under 500 kW could pass these screens easily.

• Screen F and G: The IOUs indicated that it needs to understand the aggregate impact of short circuit current contribution (Screen F) and short circuit interrupting capability (Screen G) of individual projects on distribution substations and subtransmission substations, which the ICA cannot do because the ICA only evaluates equipment on the distribution feeder. Generally, projects that fail this screen undergo a “quick evaluation” to identify any small adjustments (e.g., installation of protection device) to pass this screen. The IOUs noted that pre-information cannot be provided for Screen F, but they may be able to identify a shortlist of substations to quickly identify where projects over 500 kW may pass or fail Screen G.

• Screen L: The IOUs indicated that it needs to understand the transmission dependencies to other projects in the area with this screen. A shortlist of substations could be provided in advance related to Screen L, though this list of substations are separate and perhaps different from those pre-identified for Screen G.

The working group agreed that Screens F, G, and L required revisiting after the IOUs discuss internally whether the 500-kW limit aligns with their planning standards. The working group also kicked off discussion around using the ICA to streamline interconnection of PV projects that did not fall under a “typical PV” project profile. To make this determination around non-typical, the IOUs proposed either having the applicant provide 576 maximum output data, having the IOU perform a “quick evaluation” during initial review, or setting pre-approved “restrictions” or controls on the project. Finally, the working group discussed whether IOUs can identify where ICA value changes are known or where intra-month ICA values are becoming stale, by “flagging” that point on the ICA map. Key IT changes to the ICA portal are likely to be needed. In general, the IOUs generally supported the idea of identifying means of providing actionable information and stated that it will develop the conceptual scope internally.
On April 25, 2018, a working group meeting was held to discuss three topics. First, SCE proposed a three-track interconnection pathway whereby DERs connecting at a circuit or node that are below the ICA “with operational flexibility” (ICAWOF) value – i.e., the interconnecting DER capacity does not limit the IOUs ability to reconfigure the distribution system as necessary (though the IOUs clarified that whether a circuit can be reconfigured is not within the scope of the ICA, which is the reason why the adopted ICA methodology creates two values) – and below the ICA with no operational flexibility (ICAWNOF) value:

• Expedited Process (Category 1): Projects sized under ICAWOF do not need to provide DER profiles and create little to no risk.

• Fast Track Process (Category 2): Projects sized up to ICAWNOF are evaluated under Supplemental Review for operational flexibility and technology implementation requirements, but likely do not pose risk and do not need to provide DER profiles.

• Normal Process (Category 3): Projects sized higher than ICAWNOF pose the most risk of thermal and voltage issues if load significantly changes on the circuit, so these projects must provide DER profiles, have distribution flexibility studied in a supplemental review, have full Phase 1, 2, and 3 communications via smart inverters, and must be willing to be capable and acceptable to change DER output profiles down to the ICAWNOF value.

However, all categories, SCE reiterated that all non-ICA related screens still must be evaluated. Despite this proposal, SCE raised general concerns about the use of ICA load profiles in lieu of minimum load values in the Rule 21 study process reduces the level of margin to account for future customer load changes, leading to increased risks of future operational constraints and need for system upgrades after the interconnection is in place. Whereas the current use of minimum load values allow for some margin of customer load changes, SCE is concerned that the use of ICA values, which are based on historical loading, may trigger issues around cost allocation for upgrades at a later time. The key for energy storage interconnections will be in establishing operational profiles that do not trigger further review whether the interconnecting system is below or above the ICAWOF or ICAWNOF values. An “ICA translator” was developed by the IOUs to determine how different DERs would impact the available hosting capacity levels on every circuit and node.

Second, Clean Coalition and GPI presented an overview of automation of existing NEM and Rule 21 interconnection processes as well as their proposal to automate various parts of the process, including queue position assignment, queue publication, ICA updates, and screens not covered by the ICA. According to GPI, the end goal of full automation in the long term would be achieved when the interconnection process requires de minimis human intervention for the large majority of applications. The IOUs, however, argued that only partial automation may be possible and that it may not be cost-effective to automate non-NEM projects given the small number of such applications relative to NEM projects.

Third, the working group discussed conceptually how the typical fixed PV ICA value may be used. The typical fixed PV ICA value is currently being implemented in the first iteration of system-wide ICA and was developed using inputs from NREL PV Watts. It was discussed that an applicant submitting a typical fixed PV system can quickly pass the interconnection process by applying using the typical fixed PV ICA value. The IOUs noted that the ICA Translator can be used to develop a DER profile and to demonstrate how the project may fit under ICA values – e.g., using trackers or installing west-facing panels.

On May 2, 2018, the working group continued discussions around Screens F, G, and L. SCE presented on how it is considering whether it is possible to provide pass-fail indicators on Screens F, G, and L on existing system conditions, regardless of proposed system size, at each three-phase electrical node consistent with ICA information. For the time being, SCE indicated that this solution will be for informational purposes to inform project development choices, as projects will still need to undergo initial review for these screens. PG&E confirmed a similar approach to that of SCE regarding these screens, while SDG&E is still discussing internally before determining whether to publish these indicators similar to the other two IOUs. Meanwhile, there was some confusion in the working group during PG&E’s discussion of the connection between Screens L and M, where PG&E proposed to create a new sub-screen of Screen M (which is informed by the ICA) to flag areas of concern with synchronous generations that meet the 15% loading condition.

The IOUs also discussed the use of the ICA Translator in the Rule 21 process, how the IOUs can verify DER operational profiles, and how the IOUs can address the need to change DER operational profiles as loading conditions change, particularly as the system approaches its ICA limits. While these operational profiles are not an issue when systems are sized to be below the ICAWOF and ICAWNOF values, the IOUs are hesitant to support a proposal where the IOUs cannot request changes to DER profiles and simultaneously also having to integrate operational profiles into the interconnection process. Industry participants contended that customers would not be willing to bear the risk of a changing operational profiles, with one participant arguing for a maximum limit to changes.

On May 16, 2018, the IOUs each shared their preliminary conceptual proposals with the working group at the meeting. SCE discussed how the ICA can be used to reduce both timelines and costs of supplemental review for projects under the ICAWOF (with operational flexibility) value by informing Screens N, O, and P to be evaluated in the initial review process (instead of in supplemental review), by removing the 15% peak loading value with the ICAWOF value in Screen M (Screen M is the 15% of peak load criterion, which approximately equates to 50% of minimum load; PG&E noted that ICA calculations are based on 100% minimum load), and by replacing the current 3-MW Fast Track size eligibility limit with the ICAWNOF (without operational flexibility) value. For quality assurance purposes, SCE explained that it would need to review data inputs, algorithms to calculate the ICA values, and other external factors to ensure accuracy of ICA values. Each of the IOUs generally agreed that Screens F, G, and L are not covered by the ICA and thus would not publish “flags” indicating information on these screens, especially as review of these screens are partially automated and do not represent a long time to review. In particular, the IOUs noted that they study a transmission issue in Screen L that makes it difficult to streamline further or make more actionable. While Screens F and G could be published when exceeding certain thresholds, PG&E noted that it would be technically difficult to batch analyze by line section for short-circuit contribution ratio and interrupting capability. Unlike SCE, PG&E and SDG&E explained that it is open to consider streamlining Screen M, which determines which projects proceed to supplemental review, by conducting a 50% minimum load study but reserved the right to further study protection and anti-islanding. Overall, the IOUs seem to want to limit the scope of the ICA in the Rule 21 interconnection process, as ICA values are updated monthly and are affected by many non-IOU controlled factors. Thus, the IOUs aim to differentiate between project-dependent and system-dependent factors when identifying screens to streamline. SDG&E has been the least progressive in these discussions as they do not view the current ICA methodology as replacing or displacing any of the Rule 21 screens – only serving to supplement and improve review under the existing screens.

On June 13, 2018, a brief follow-up working group call was held to discuss SCE’s proposed Fast Track eligibility MW Limit of either 3 MW or the ICAWNOF value, whichever is greater, as well as Fast Track eligibility non-exporting energy storage systems over 30-kVa nameplate capacity and falling under the ICAWNOF value. The working group noted that work is still needed to answer the cost allocation question for who pays for the upgrade if the systems are sent for detailed studies, during which the magnitude of any upgrades would be identified. While SCE has been making progress to put ‘pen to paper’, the other IOUs have yet to propose their detailed ideas.

On June 20, 2018, a working group call was held where PG&E and SDG&E presented their draft concepts. PG&E presented two draft proposals to replace size limitations for Fast Track eligibility in Rule 21 with the ICA and to replace certain Rule 21 screens with the ICA, while noting that PG&E was facing technical challenges (e.g., crashing IT systems) with producing ICA values and challenges with how the ICA results may be favorable for some projects but not others. On their first proposal, PG&E proposed to determine the ICA value at the time of interconnection that could result in changes in queue position and to determine if the ICA value changed based on queue position such that the project is not eligible for the Fast Track process. The current Fast Track eligibility criteria sets no threshold for non-export generating facilities or NEM-1 generating facilities and a 3-MW threshold (interconnecting at 12-kV or higher) for NEM-2 and exporting generating facilities. As a result, the size thresholds for Fast Track eligibility are eliminated in favor of an ICA approach. An illustration of the proposed “validation study” is shown below.

On its second proposal, PG&E proposed to conduct a validation for Screen M, which focuses on whether the aggregation generation is less than or equal to 15% of the line section peak load and is the main screen that moves projects over to Supplemental Review. In other words, similar to the size thresholds, whether the ICA indicates “room” for accommodating larger systems determines Fast Track eligibility, according to PG&E’s proposal. An illustration of the proposed “validation study” is shown below.

Stakeholders disagreed on whether the ICA should be used to bypass certain Initial Review technical screens as opposed to replacing the Fast Track process. Others expressed their views that using a 3-MW threshold is easier to administer and manage applicant expectations.

SDG&E then presented their draft concept that is focused on using the current ICA methodology to supplement and improve the Rule 21 screens but not to replace or displace any of them. SDG&E noted that they propose to use ICA internally for validation and verification of R21 screens, but the results of ICA would not directly replace any of the screens. Additional verification will be required to make sure that ICA information is correct. The goal of the new process is to stay within the current time frame it takes to interconnect projects. Basically, SDG&E’s proposed concept would use the ICA for verification does not really streamline existing review processes.

On June 27, 2018, an in-person workshop was held to discuss the IOUs' proposed validation study that seeks to understand whether a project will see upgrades and understand how often customers' expectations are not met in the application process due to the changing queue, leveraging the ICA. The results of the study are meant to inform future queue discussions, identify technical requirements and criteria on how/when to update the ICA, and identify how often project results different when compared to business-as-usual. Stakeholders identified that clarity is needed on how the queue currently works and disagreed over whether understanding the frequency that the scenario occurs is relevant. Meanwhile, the IOUs seemed to be in disagreement on whether using the ICA in the Fast Track eligibility screen results would result in a more streamlined process than the existing process due to validation step required in case the ICA value is not correct. 

Several other ideas were proposed. First, CALSSA presented on how voltage as an ICA limit should be treated when a project using smart inverters with reactive power priority applies for interconnection on a circuit where voltage is the limiting factor and proposed that projects subject to Screen P should be assessed for their voltage impact, if voltage is the limiting criteria - i.e., if the x/r ratio is high, volt-var will be highly functional and the project should connect without upgrades. The x/r ratio (where x = reactance and r = impedance) are dependent on the length of the feeder, circuit voltage, and overhead/underground lines. With reactive power priority settings (effective July 26, 2018), systems will be solving any potential voltage impacts before those impacts would otherwise reach the grid and CALSSA posed that it would be unfair if customers are required to activate volt-var with reactive power priority if interconnection review does not account for their benefit. The IOUs responded that reactive power priority will be considered within Supplemental Review studies and the x/r ratio study may not be the exact method for evaluation (i.e., may require network models). SCE noted that fixing voltage issues using reactive power priority would increase current due to the need to absorb reactive power, which lowers the thermal ICA limit. In other words, mitigating for the voltage ICA limit may not lead to a higher ICA value due to a lowering of the thermal ICA limit that results. 

Second, CALSSA presented on recommendations to avoid "queue stacking", including requiring Rule 21 and WDAT projects to have proof of offtaker as a condition of application submittal and setting additional milestones to keep the queue moving. The CPUC was undecided on whether this issue should be addressed in RFOs or changes in the interconnection process (e.g., financial securities for upgrades). Finally, there were two other proposals around the need to better define and enforce timelines (CALSSA) and automate the interconnection process (GPI and Clean Coalition). 

On July 11, 2018, the IOUs’ draft implementation matrix was reviewed. The IOUs noted a preference to eliminate Fast Track eligibility criteria in favor of using the ICA values, with individual IOUs differentiating their specific positions within the draft matrix. PG&E and SDG&E preferred eliminating Fast Track eligibility criteria while SCE indicated that it will continue to process NEM systems less than 30 kW to continue through Fast Track processes. SCE discussed how it needed to see the pros and cons of Fast Track eligibility for NEM systems larger than 30 kW. Given the challenges in ensuring that ICA values do not become stale, the IOUs also indicated that there may need to be Supplemental Review for projects in cases where the ICA value is no longer found to be valid to determine if upgrades are indeed needed. CALSSA alternatively proposed that an additional upfront process or an additional step in Screen N be considered where customers have options to downsize or modify their application without affecting queue position while avoiding the Supplemental Review process. SCE, however, raised timing concerns for this approach as the modification decision would need to occur quickly (e.g., within 5 business days) to not affect other customers in the queue. Stakeholders also spent time discussing Screen M2, M, and I as proposed in the implementation matrix. Requests for clarification were asked on the “buffer limit” related to Screen M2 and the policy justification for Screen M for non-export projects. PG&E clarified that non-export facilities can be charged for grid upgrades under Screen M if upgrades are determined as being needed specifically due to disappearing load. This issue will be addressed in Phase 3 under Issue #29.

On July 17, 2018, an in-person working group meeting was held that provided more detailed follow-up discussion on Screens I, J, L, and M. The IOUs began with a presentation on how the operational flexibility criteria will be applied. The ICAWOF value for each of the 576 hours will be the lowest value from the set of voltage (SSV), power quality (PQ), thermal (T), protection (P), and safety (S) at each hour, with the ICAWOF not allowing for reverse power flow back to the substation low side bus unless the lowest value from the “set” is lower than the minimum load of the circuit of that hour.  For example, if T = 4.5 MW, SSV = 4.5, PQ = 9, P = 6, and S = 5, then the ICAWOF will be 4.5 MW (the SSV value), even though S = 5.0. When the safety value is lower than the other values, the ICAWOF and ICAWNOF values will be the same value at that hour. Questions were raised on the use of an 80% “buffer” on the ICAWOF value since operational flexibility should already be calculating such a buffer in the hosting capacity value. The IOUs, however, argued that some buffer is needed since actual conditions may vary from forecasted loading conditions by a roughly 10% error margin. Subsequently, the working group began discussions on clarifications and potential modifications to the various Rule 21 screens. The working group discussed the merits of whether projects failing Screen M should be sent to Detailed Study, discussed the proposal to expand Screen J to all projects 30 kVA and below, and discussed the proposal to include transmission overvoltage and transmission anti-islanding tests in Screen L. Next, the working group continued discussions on options for the potential validation step in the Rule 21 process to verify accuracy of ICA results. The IOUs plan to propose what results are shared with applicants if ICA results change, given technical accuracy and customer confidentiality issues, and how they plan to track changing ICA results over time.

On August 8, 2018, an in-person workshop was held where the IOUs proposed to modify their approach to Screen I so that non-exporting systems are subject to Screens J, K, L, M, N, O and P because of potential negative local voltage and power quality impacts, similar to an exporting NEM system. This change may cause non-export projects to fail Initial Review and potentially subject them to additional studies and potential upgrades to ensure the safety and reliability of the grid, but the IOUs emphasized that non-export generation can impact load on the feeder and result in power quality issues requiring mitigation under Rule 2 requirements. The non-IOU stakeholders generally did not agree with this proposal and planned to submit an alternative proposal.

On August 21, 2018, the working group met to finalize the proposal. The IOUs were converging on SCE’s proposal but details on how the IOUs will validate ICA results and explain deviations from ICA to interconnecting generator during initial review still needs to be worked out. The non-IOU stakeholders are also preparing a counterproposal. Importantly, the broad data redaction implemented by the IOUs in the DRP proceeding has also caused all ICA data to also be redacted, which has impacted some of the work on this issue. The IOUs offered to provide the working group with some aggregated data from the ICA and some sample circuits as a workaround to inform how the working group can propose to incorporate the ICA results into the Rule 21 interconnection process. The IOUs fulfilled this data request on September 28, 2018.

On October 31, 2018, the Working Group #2 Final Report was filed that highlighted final positions on the proposals, where full consensus was achieved on several issues but only partial or non-consensus on others. Specifically, the report highlighted threshold considerations for cost considerations, implementation dependencies, and ICA validation. Specifically, the proposals put forth by the working group would use either 100% of the lowest ICA-OF value or a buffered ICA-OF curve. The IOUs explained that their opposition to the use of the ICA-OF curve is due to internal loop circuits, where the current ICA does not account for a margin for operational flexibility within a single individual circuit. The ICA-OF value only looks at the limits that maintain operational flexibility between different circuits (i.e., reconfiguration of circuit with other circuits) and thus would not reflect an updated ICA value for ‘internal’ reconfiguration within a single circuit. PG&E, however, was open to Tesla’s suggestion to limiting and localizing the ‘internal loop circuit’ issue to certain circuits (i.e., using the lowest value of the ICA-OF profile) while leveraging the ICA-OF value where such issues do not exist. PG&E also clarified industry’s concern around using the existing Screen M methodology where nameplate generating capacity is compared with 15% of the peak load on a circuit as part of an internal review to supplement but not replace the use of the ICA in interconnection review processes. This dual approach would guard against out-of-date ICA values, according to PG&E. Industry stakeholders pushed for further changes but the IOUs contended that the recommended changes benefit a few and would have high costs.

In a response to a data request on the internal loop issue, SCE explained that reconfiguration is only possible for feeders that have internal three-phase electrical loops. SCE estimated that it has anywhere between 80 to 100 feeders that allow for internal reconfiguration, depending on how feeders can be rearranged over time.

Operating Conditions to Perform Within ICA (Issue #9)

Background

On May 16, 2018, preliminary discussions on Issue 9 were held. Calcom presented on their views of Distributed Energy Resource Management Systems (DERMS) that provide IOU controllability of DERs using production curtailment to manage DERs in real time and allow DER providers to avoid upgrades by agreeing to some maximum level of curtailment as a function of some kW percentage over the course of a year. The IOUs, however, seem to view DERMS as being several years away from wide-scale viability. Meanwhile, CALSSA proposed the idea of scheduled curtailments using certified equipment for set times of the year or when certain operational thresholds are met, given that smart inverter requirements were recently adopted. Specifically, CALSSA presented their different views on the interconnection review categories where Category 1 projects would be eligible for expedited interconnection under a “no curtailment” agreement, Category 2 projects would be eligible for expedited interconnection under a “limited curtailment” agreement (e.g., up to 5% of generation in any interval if ICA is reduced by circuit load reduction), and Category 3 projects would require full review.

On May 22, 2018, a working group call was held that discussed the overlap of Issue 8 and 9 as well as the Issue 9 scoping memo developed by Gridworks. The scope of the working group will include defining the “conditions of operations” and how they can be proposed, assessed against the ICA constraints, verified, and integrated into interconnection applications and agreements. In particular, one of the key issues related to this issue is the consequences of changing load on the circuit to defined operational profiles.

Proposal Development

On July 17, 2018, an in-person working group meeting was held where Calcom Energy proposed their idea on how systems could operate during predefined periods with conditional operational profiles and controls to more optimally take advantage of available hosting capacity, even as ICAWNOF values are exceeded during certain times. Specifically, DER providers would need to submit 288-hour programming profiles to the IOU for approval with the Rule 21 application, with failure to follow the agreement resulting in punitive measures. The IOUs responded that this proposal fails to account for how non-export relay systems make real-time decisions to maintain safety and reliability, whereas the ICA is based on historical system conditions, making the Calcom proposal a potential risk to safety and reliability.

On August 29, 2018, the working group met to discuss more details on the proposal. To take advantage of hosting capacity available above the ICAWOF value, the proposal included three main parts:

• The DER customer submits a 288-hour “limited generation profile” as part of their interconnection application to determine whether the profile fits under the ICAWNOF value plus some buffer.

• The DER customer agrees to smart inverter functionality and local controls to ensure actual operations conform with the limited generation profile.

• The DER customer agrees to allow future reductions to the generation profile up to the minimum ICAWNOF under defined circumstances.

Given the novelty of this proposal, stakeholders proposed moving this idea forward in stages, starting with higher buffers and moving to lower buffers as the accuracy of the ICA values improves and technology controls become more familiar. The IOUs expressed concerns about how the ICA value is a planning variable based on historical data plus safety margins, which may not support real-time operation. The IOUs also raised concerns with this proposal because of errors in forecasting of generation, ICA values, and realizing needed generation reductions, as well as insufficient experience with inverter and local controls.

On October 31, 2018, the Working Group #2 Final Report was filed that would modify the interconnection procedures to allow a DER to submit a “Limited Generation Profile” as part of their interconnection application, to require that customer to enable generation profile limiting functionality, and to allow utility limited future opportunity to alter that profile if circumstances warrant. Parties did not reach final consensus. In comments, the IOUs expressed major doubts and opposition to the proposals for a number of reasons, including the inability to actively communicate with DER systems, the lack of field testing to demonstrate usable generator constraints, and lack of a standard to certify DER capability to limit output to different levels at different times of the year. CALSSA, however, explained that Working Group #3 is actively discussing certification of power control systems and recommended that the CPUC approve the proposal in concept with condition that a protocol for certification of functionality is adopted.

Incorporating ICA in Cost Allocation & Responsibility (Issue #10)

Background

On August 1, 2018, the first scoping discussion for the coordination of the ICA with the Rule 2, 15, and 16 processes was held. The meeting focused mostly on providing an overview of the current Rules 2, 15, and 16 process and how the Rule 21 EPC process could become more consistent and transparent to the interconnection customer. Gridworks shared its draft scoping memo on Issue #10 that posed questions around ways to coordinate these results and processes.

Proposal Development

On August 29, 2018, the working group brainstormed “cross-over” issues among Rules 2, 15, and 16 with the Rule 21 processes as it relates to ICA incorporation. CALSSA presented its proposal to have a common ID number, start the Rule 2/15/16 processes concurrently with the start of interconnection review if special facilities are needed, and create timelines of a maximum of 60 days for design and 60 days for construction of all upgrades below the substation.

On October 31, 2018, the Working Group #2 Final Report was filed that discussed standard timelines for design and construction of facilities in Rule 21. Specifically, CALSSA proposed establishing three months for design and three months for construction as the standard expectation. In comments to the final report, the IOUs opposed this proposal because projects have varying characteristics and sought to maintain the ability to exceed the timelines if needed on a project-specific basis.

Notification Only for Non-Export Storage (Issue #11)

Background

On August 1, 2018, a conference call was held that began scoping discussions for the consideration of whether a notification-based approach in lieu of an interconnection application can be created when non-exporting energy storage systems have a negligible impact on the distribution system. This is an issue that CESA pushed to have scoped in, and it will consider the Initial Review screens that non-export systems would likely pass, the types of non-export systems that would qualify, and other requirements (e.g., eligibility, contractual obligations, and compliance) to qualify for this process. The discussions began with a consideration of the definition of “notification-based”, “non-exporting”, and “negligible impact”. Stem facilitated a discussion given previous efforts in the previous rulemaking and how this process could be revisited given learnings from pilots and availability of the ICA analysis. Stem also proposed a ‘strawman’ that established criteria where storage is non-exporting, its nameplate capacity is less than 75% of the ICA value at the location, and no changes to customer electrical panel or metering are needed, and if all criteria are met, the IOU would return a countersigned interconnection agreement within 15 business days. Under the ‘quick notification’ proposal, Stem proposed criteria for where non-exporting systems of 30 kW or less of storage nameplate capacity could be installed with notifications within five business days to the IOU.

Proposal Development

On August 8, 2018, Gridworks circulated a draft scoping memo to address Issue #11, which included pre-studying certain parts of the grid and considering specific system-wide thresholds for Screen F and G to determine whether non-export systems could pass Screens F and G.

On August 31, 2018, the IOUs shared their draft results from the expedited interconnection pilot for non-export energy storage, which highlighted significant reductions in interconnection process time, though PG&E indicated that it wanted to investigate further on whether timeline improvements are attributable to internal or external processes. Energy storage developers are aiming to develop non-export streamlining procedures consistent with small NEM streamlining procedures.

On October 31, 2018, the Working Group #2 Final Report was filed that explored what criteria would be used to determine which projects would be eligible for a notification-only or other expedited process for non-exporting storage systems. However, the working group did not reach the point where it could recommend adopting a notification-based approach in lieu of an interconnection application at this time. The report recommended how the near-term focus should be on how the interconnection application could be expedited in order to reduce the time and cost of interconnecting non-export storage systems. The report noted how full coverage of this would require further effort and how this may overlap with Issue 25, which plans to consider whether any revisions to the expedited process for non-exporting storage systems could be revised to support tariff principles of technological neutrality and consistency across the IOUs.

Working Group 3

Background

On November 28, 2018, a kickoff meeting for Working Group #3 was held on that discussed the order, time needed, and pairing of issues that were scoped in. Gridworks will again facilitate this working group, who offered different pathways to ensure effective input from stakeholders and timely resolution of the issues. CESA will “sponsor” or provide active input into the following issues:

• How should the CPUC coordinate CPUC-jurisdictional and FERC-jurisdictional interconnection rules for BTM DERs, including modification of queuing rules for Rule 21 and Wholesale Distribution Access Tariff (WDAT) projects seeking to interconnect at the same location, clarification of the rules for projects wanting to transfer between the Rule 21 and WDAT queues, and streamlining of the transfer process? (Issue #20)

• Should the CPUC consider issues related to the interconnection of electric vehicles and related charging infrastructure and devices and, if so, how? (Issue #23)

• What should be the operational requirements of smart inverters? What rules and procedures should the CPUC adopt for adjusting smart inverter functions via communication controls? (Issue #27)

• How should the CPUC coordinate with the IDER proceeding to ensure operational requirements are aligned with any relevant valuation mechanisms? (Issue #27)

• How should utilities treat generating capacity for BTM paired solar and storage systems that are not certified non-export? (Issue #28)

On June 14, 2019, the Rule 21 Working Group 3 Report was submitted and a workshop was held on June 21, 2019 to answer questions for the assigned ALJ.

On November 27, 2019, a Ruling was issued that posed questions on each of the Working Group 3 proposals.

Distribution Upgrade Timelines (Issue #12)

Background

On December 12, 2018, an in-person workshop was held to begin discussion around improvements to certainty around timelines for distribution upgrade planning, cost estimation, and construction. The IOUs generally supported a more transparent and data-driven approach to design and construction timelines. Instead, stakeholders focused on a small subset of key timelines where there have been significant bottlenecks and delays.

Proposal Development

On January 10, 2019, CALSSA proposed that a timeline be established for NGOM installations, timeline data be reported, and notifications and penalties be considered for timeline exceedances. IREC added several proposals around establishing reporting criteria and a mechanism to ensure and/or improve compliance related to the “baseline” timeline (e.g., through a more direct financial incentive system).

On February 13, 2019, IREC submitted a proposal on 20 metrics to track while SCE and SDG&E submitted proposals to establish tracking mechanisms with quarterly reporting starting on July 2019 and to establish customized schedules agreed to by the developer and utility. Consensus was reached on tracking 12 specific timelines but there was no consensus on the timelines for request for modifications, for scheduling commissioning tests, and for line-side variance requests – the last of which CALSSA noted as a “pain point” for developers. There was consensus that an overall goal for timelines is that 95% of non-NEM projects and NEM projects greater than 30 kW projects are meeting the individual timelines within two years of the start of tracking.

Itemized Billing for Distribution Upgrades (Issue #15)

Background

On December 12, 2018, an in-person workshop was held to begin discussion around itemized billing for distribution upgrades. The IOUs explained that they each address cost itemization uniquely, while non-IOU stakeholders requested the itemization of actual costs to follow the Unit Cost Guide and follow a standardized format. The IOUs committed to look into if and when a proposal to itemize labor and materials costs is possible.

Proposal Development

On January 23, 2019, PG&E presented a fixed cost option for interconnection and distribution upgrades on NEM projects over 1 MW. CALSSA and Tesla responded in support of a fixed cost option but requested that the current payment schedule remains in place, particularly for larger projects. SCE also presented their “construction bid” model to set the customer cost based on estimates after final engineering. Though there is a lack of competition to provide checks and balances, SCE indicated that developers may prefer a system that provides greater cost certainty.

On February 8, 2019, SDG&E submitted a proposal to provide itemized billing that is consistent with the cost categories set forth in the Unit Cost Guide, while SCE indicated that it does not have the automation capabilities to do the same. PG&E reviewed completed projects and determined that billing based on an estimate would have resulted in an under collection of project costs. Importantly, the CPUC staff raised the question of the value proposition of cost itemization.

Third-Party Construction of Upgrades (Issue #16)

Background

On January 10, 2019, GPI and Clean Coalition started discussions on the benefits that third-party installations of distribution upgrades would improve interconnection costs and timelines, which can be accomplished while adhering to IOU design specifications. As a result, developers and contractors would have more control over timing, costs, and choice of contractors performing the identified upgrades. GPI and Clean Coalition thus proposed to strike language in the Rule 21 tariff disallowing third parties and to have the IOUs produce eligibility criteria for third parties to conduct the construction. SMUD and IID were cited as examples of utilities that have allowed applicants to build their own facilities.

Proposal Development

On January 16, 2019, GPI and Clean Coalition clarified that they are not proposing changes to the current Rule 15/16 third-party requirements but stakeholders broadly agreed that there needs to continue be discussions on the possibility of allowing third-party contracting on energized equipment or existing facilities upgrades, while also considering the legal, liability, outage scheduling, and supervision issues. The joint proposal from GPI and Clean Coalition was reviewed by multiple parties, and the IOUs agreed to incorporate Rule 15 eligibility rules and to remove “discretion” language in the Rule 21 tariff. There was no consensus on whether third-parties could work on existing de-energized systems. The IOUs said that third-party work can only take place subject to the language in Rule 15, that is, building new facilities, after which the utility would remove any existing facilities itself, at its discretion. There were no scenarios put forth in which a third-party could work on existing de-energized facilities.

Rule 21 & Wholesale Distribution Access Tariff (WDAT) Coordination (Issue #20)

Background

CESA was tasked with leading the discussion on modification of queuing rules for Rule 21 and Wholesale Distribution Access Tariff (WDAT) projects seeking to interconnect at the same location, clarification of the rules for projects wanting to transfer between the Rule 21 and WDAT queues, and streamlining of the transfer process. CESA drafted an issue brief that discussed how WDAT interconnection processes pose potential barriers if they impose duplicative or potentially costly site-specific studies, as BTM energy storage resources aim to leverage its export capabilities and participate in the NGR model in the future.

Proposal Development

On March 6, 2019, CESA introduced a WDAT Lite concept for Fast Track consideration of DER aggregations that have already been studied at a site level under Rule 21. We sought to understand where studies overlap and create a process for aligning the two tariffs, and sought opportunities for streamlining some standardized configurations, including a limited export case.

On March 20, 2019, further discussion was held on a conference call where the IOUs provided clarifications on how an “exit ramp” works for a Rule 21 transition to the WDAT process, assuming there are no operational changes. Tesla revealed that projects may not be able to operate their system until they go through the WDAT interconnection agreement milestone and have that agreement administratively submitted through the new resource implementation process. A subgroup will further clarify the technical and legal requirements.

On March 27, 2019, the working group reviewed and discussed the IOUs’ clarifications on the exit ramp and CESA’s four proposals. The IOUs explained that a re-study process is needed for any operational change, especially for one moving from non-exporting to exporting, with short circuit duty contribution being the key one.

On April 17, 2019, Tesla presented the different use cases where projects may want to transition from a Rule 21 system to a WDAT system. The CAISO explained that the NRI is intended to establish whether a new resource can operate in the CAISO market, which requires an identified and completed WDAT interconnection agreement, though the existing Rule 21 agreement could be recognized. However, Tesla clarified that there is a minimum 203-day mandatory timeline for the NRI process, and the CAISO posed the question to the IOUs on whether WDAT interconnection agreements could have a future effective date (instead of being effective at the time of submittal). The IOUs discussed how this requires further internal discussion, including around how to only have one agreement in effect at one time (e.g., cancellation of Rule 21 agreement on same day as PTO date of the WDAT agreement).

On April 24, 2019, the CAISO confirmed that a distribution-interconnected resource would need to have an interconnection agreement with the utility distribution company to start the NRI process with the CAISO. The CAISO would accept either a Rule 21 exporting or WDAT interconnection agreement. Under the Rule 21 exporting interconnection agreement, the resource would be modeled at its maximum export capability but would need to start another NRI project to be modeled if the agreement changes (e.g., an increase in the export limitation or allowance). A resource with a Rule 21 non-exporting interconnection agreement would not be considered in the NRI process and may qualify for continued participation in DR participation models under a registered resource ID. Importantly, the CAISO stated that it would not accept a future-dated interconnection agreement but also noted that it will be reducing the amount of time that it takes to complete the NRI process to a minimum timeframe of approximately 84 days based on changes being made to the full network model build scheduled for late 2019. However, for Rule 21 exporting interconnection agreements, the system would be able to continue to operate during the NRI process.

Interconnection Portal Improvements (Issue #22)

Background

On January 4, 2019, GPI organized an initial sub-group call to frame and discuss the large number of possible ways that the portals could be improved. GPI asked the IOUs on what latest activities on portal improvements, but the IOUs also discussed how funding sources may be limited to pursue any other improvements. CESA focused on how V2G DC interconnections could be facilitated through interconnection portal improvements.

On February 21, 2019, GPI shared the results of the survey responses on portal improvements, which ranged from accommodating V2G DC interconnections, removing customer interactions, adding a customer help desk, implementing a notification-only process for certain pre-defined, standardized configurations, acceptance of online payments, elimination of redundant requirements, and auto-population of customer data and existing interconnection data. One key limitation is that SCE highlighted how the GRC would be the expected funding mechanism.

Proposal Development

On March 20, 2019, GPI presented the final list of 18 recommendations for interconnection portal improvements. With GPI-generated “impact scores” to prioritize the survey recommendations, the working group discussed which of the recommendations have already been addressed, are in the process of being addressed, and require further discussion at the next meeting. SCE confirmed that V2G systems interconnecting like an energy storage system should face no problems in navigating the portal but adding an EV option in the application process may be helpful for tracking purposes only.

On March 27, 2019, a workshop was held to discuss priority portal improvements and outlined a portal improvement roadmap and plan. The group reached a consensus that the CPUC should issue direction on 18 sub-proposals for specific types of portal improvements contained, taking into account utility and other party as well as planned or currently ongoing improvements that may be related. For functions that require improvements to the IOU’s existing electronic processing systems, the working group agreed to recommend that the CPUC should provide clear direction as to cost recovery mechanisms in support of functions to be implemented under CPUC order that do not have existing approved recovery, while evaluating whether the benefits to the public outweigh the costs.

Vehicle-to-Grid (V2G) Interconnection (Issue #23)

Background

On January 10, 2019, CESA presented an issue brief on several key ideas for proposals:

• Establish applicability of Rule 21 only when bi-directional capabilities are activated and utilized

• Authorize V2G DC interconnections and make the appropriate modifications to the Rule 21 tariff and portal

• Broaden the definition of “smart inverter” to include a system of components and allow certification to IEEE 1547 standards to enable V2G AC interconnections

• Clarify a path for parties to interconnect AC V2G systems on a timely basis for experimental and/or temporary use until the appropriate rules are updated in the future, consistent with any recommendations resulting from R.18-12-006 or other transportation electrification proceeding

Nuvve and Honda also presented on the issue with an angle toward the view from OEMs and from recent pilot experiences. Following the workshop, CESA was tasked with forming a sub-group to develop interconnection processes and procedures related to V2G DC interconnections. In an updated proposal, CESA recommended changes to the applicability and definition sections of Rule 21 only when bi-directional capabilities are activated and utilized, including some changes around allowing multiple generators under Section N (expedited process for non-exporting storage) to enable fleet applications. At a high level, we sought to establish some level of equivalency to non-exporting storage while adapting it to the V2G use case.

Proposal Development

On February 13, 2019, the IOUs presented their feedback on our proposal, with PG&E and SCE holding the view that Rule 21 should still apply where V2G-capable systems do not have V2G capabilities activated, and expressing that the IOUs need to verify and guarantee that these capabilities are turned off, potentially via certification. SCE, however, seemed to be receptive to streamlined interconnection processes equivalent to Sections N and O. CESA has concerns about the potential for excessive verification steps beyond the minimum of manufacturer attestations or online form submissions from dealers. PG&E pushed back against the V2G AC proposal to broaden the definition of “smart inverter” by noting that the onboard inverter must be UL 1741-SA certified, which is the only certification recognized in Rule 21, or compliant with a new SAE standard compliant with IEEE 1547.1, once the SAE standard has been reviewed and accepted by the IOUs. The IOUs said they need to determine if IEEE 1547.1 can supplement or comply with UL 1741 to enable EVs. SCE recommended a working group process to review the SAE standard.

On March 6, 2019, discussions continued at an in-person workshop meeting. Regarding CESA’s Proposal 1 to clarify that V1G must comply with Rules 2, 3, 15, and 16 and that Rule 21 does not apply to V1G, stakeholders generally agreed on a change to Rule 21 tariff language. All parties agreed that any bidirectional EVSE must be Rule 21 compliant with UL 1741-SA. The working group recognized the “temporal problem” of the need in the long-term for standards to test and certify there is zero export when the bidirectional functionality of an EVSE is disabled (i.e., to certify that indeed “off is off”) and for safeguards that it will remain disabled. The IOUs explained that they need more information to judge how prevalent and important this issue will be – e.g., a customer wants to first use an EVSE in charge-only mode with a bidirectional EVSE capability that is latent for later enabling. Depending on how prevalent and important, standards bodies may or may not take up the issue expediently. In the meantime, the working group recognized the need for an interim solution and proposed that utility labs test those models of EVSE that are bidirectional capable and verify that indeed bidirectional functionality is disabled. EVSE equipment tested in this way may be interconnected as non-exporting storage and will require a customer to be contractually obligated to keep bidirectional capability disabled. Regarding CESA’s Proposal 2, the working group generally agreed at the March 6 workshop that any bidirectional inverter used for V2G DC (stationary inverter) interconnections, as an EVSE, must satisfy all Rule 21 requirements, the same as any other stationary inverter.  No changes to Rule 21 were determined to be needed to authorize V2G DC (stationary inverter) interconnections.

On March 15, 2019, a technical sub-group followed up on the interim solution. SCE agreed that no interconnection request is required when operating as V1G only but would prefer that EVSEs disable bidirectional functionality as a factory default. To address IOU concerns about changing modes and creating potential backfeed, NRTL tested and certified software controls certifications were cited, including UL 1741, the new CRD for Power Control Systems, and UL 1998 (Software for Programmable Components). To enable bidirectional capability, EVSEs would follow the same process as currently used for stationary storage systems, where manufacturers send compliance test certificates to the IOU.

On March 27, 2019, the sub-group reported out their outcomes and the broader working group had final discussions on Proposals 3 and 4 on mobile inverter standards, Proposal 5 on mobile inverter pilots, and portal improvements for EVSE tracking and other purposes. CESA and Gridworks prepared a final proposal and report that included the following consensus proposals:

• Recognize that in the case of single-directional V1G with no export capability, Rule 21 does not apply; V1G must comply with Rules 2, 15, and 16

• Modify Rule 21 Section B.4 to clarify that Rule 21 applies to the interconnection of both stationary and mobile energy storage systems

• Add a definition to Rule 21 for V2G devices

• Recognize that V2G-DC EVSEs (stationary inverters for DC charging of vehicles) may be interconnected under the current Rule 21 language, with no Rule 21 language changes or additional authorization needed, provided that the EVSE meets all Rule 21 requirements, including UL 1741-SA and other updated smart inverter standards

• Allow V2G-DC (stationary inverter) systems to connect as load and operate in one-directional (charge-only) mode, despite V2G capabilities, upon satisfying pre-defined criteria, including UL CRD (Power Control Systems) and UL 1741-SA certification, testing to demonstrate that EVSE will not discharge if set to one-directional mode and will not inadvertently change operational mode, and factory default setting to one-directional mode

• Allow bi-directional mode to be enabled for a V2G-DC (stationary inverter) system only upon receiving Permission to Operate (PTO) from the utility

• Modify interconnection portals to enable simple tracking of V2G interconnections, such as by adding new EVSE inverter types in drop-down menus or flagging interconnections as V2G

• Establish a sub-group inviting stakeholders from the Smart Inverter Working Group and SAE, among others, to develop technical recommendations to enable V2G-AC (mobile inverter) interconnections

V2G AC Interconnection Technical Sub-Group

On May 29, 2019, CESA submitted a motion in R.17-07-007 as well as a motion in R.18-12-006 to establish a sub-group and schedule a joint workshop to introduce sub-group proposal on mobile inverter technical requirements for Rule 21 interconnection. CESA laid out the proposed scope and schedule but also argued for the grounds for relief based on how V2G AC interconnection issues require several more months of dedicated technical discussion that should not hold up all Working Group 3 proposals nor await a final decision to merely initiate discussions. CESA also argued that other procedural venues may not resolve these V2G AC interconnection issues in a timely manner and/or would not receive the dedicated technical focus.

On August 23, 2019, a Ruling was issued that established a subgroup in R.17-07-007 and R.18-12-006 to discuss and identify existing standards to fulfill safety requirements for the interconnection of a mobile inverter. The Ruling found the current need for an interconnection pathway to be important and noted that the goal of the subgroup is to ensure EVs can safely interconnect with the grid, which is a technical issue that directly impacts transportation electrification proceedings at the CPUC. Specifically, CESA’s proposed scope was adopted, including:

• Mapping of existing NRTL standards

• Determination of how well the existing standards can be combined to fulfill safety requirements for interconnection of a mobile inverter at one fixed point

• Recommend language citing existing standards to enable Rule 21 interconnection, or if existing standards are insufficient, then notify the testing laboratories to inform them of gaps in standards

Importantly, the Ruling granted the motion because of robust automaker response, so participation from these parties will be critical going forward.

Facilitated by CESA, the sub-group kicked off with a background presentation from CESA on the various V2G interconnection proposals from the Rule 21 Working Group 3 process and an overview from SCE and SAE on the existing standards mapping completed thus far. The scope of the sub-group was determined to focus on one-to-one interconnections at a single point of interconnection, with the sub-group moving to cover many-to-one interconnections if time permits. Over the course of multiple biweekly meetings, SDG&E provided an overview of the Rule 21 interconnection process, Nuvve presented on a preliminary framework for the existing standards mapping process, and SCE presented a Rule 21 interconnection matrix for smart inverter functions, testing, and certification. In response, the automotive industry completed portions of the matrix by mapping existing UL and SAE standards to the smart inverter requirements and also proposed a strawman proposal on self-certification using SAE self-certification for the EV mobile inverter and UL 9741 third-party certification for the EVSE.  

On November 6, 2019, a sub-group meeting was held to discuss the draft report and the initial gaps analysis, which includes a number of areas where updates to SAE standards are required and different pathways for communication protocols need to be identified.

On December 11, 2019, CESA submitted a final report that identified the following key gaps in existing standards in meeting current Rule 21 interconnection requirements:

• Various updates needed to UL 1741 that would make it applicable to vehicles

• Various updates needed to SAE J3072

• Standards and certifications for mobile inverters to receive default settings

• IEEE 1547 and IEEE 1547.1 standards do not account for default settings to be delivered to the inverter at each site

• Dynamic lists to authenticate and authorize certified EVs for discharge

• Various updates needed to UL 9741

• Matched pair certification for EVSEs to UL 9741 and EVs to SAE J3072

• Difference in perspectives from automotive manufacturers seeking self-certification pathway for mobile inverters while Rule 21 requires third-party certification

The report did not make direct recommendations for the CPUC, but it provided guidance to NRTLs and certification bodies to address the identified gaps through standards modifications and updates.

CESA discussed how an initial phase of V2G AC interconnections would leverage UL 9741 for the EVSE and SAE J3072 for the EV with the appropriate modifications and updates to these standards. In addition, to support CPUC action, CESA recommended that the subgroup should be reconvened when the necessary updates and modifications have been made to the standards discussed in the Final Report, but EV testing results should not be attached as a precondition. Finally, CESA recommended that a CPUC proceeding should consider the jurisdictional question around internal certification and further review the manufacturers internal testing process.

See CESA’s comments submitted on January 6, 2020 on the Subgroup Final Report

Vehicle-Grid Integration Council (VGIC) supported many of CESA’s recommendations and recommended that the CPUC and IOUs could rely on federal government entities such as the National Highway Traffic Safety Administration (NHTSA) to accommodate internal certification through the OEM testing procedures. VGIC also proposed the OEMs becoming a NRTL, an idea that PG&E and SDG&E also recommended. UL also submitted comments indicating its concern over a level playing field by giving V2G AC resources an option for self-certification as compared to other utility-interactive and interconnected DER products. Meanwhile, SCE proposed a conceptual timeline to potentially enable an initial phase of V2G AC interconnection implementation by early 2022. The IOUs generally affirmed the need to maintain the third-party testing requirement. PG&E and SDG&E added that the OEMs should be required EV test results for UL 1741 prior to reconvening the subgroup.

Vehicle-to-Grid (V2G) Interconnection (Issue #23)

Background

On March 4, 2019, Clean Coalition prepared an issue brief on the Rule 21 cost of ownership, which is a one-time charge and calculation of the ongoing costs to operate and maintain transmission and distribution system infrastructure. Rates are set in General Rate Cases because utilities need to know how much O&M that they can put into their revenue requirements for all grid construction. Clean Coalition contended that the cost-of-ownership charges are not directly related to interconnection of DERs. Clean Coalition recommended review of the calculation and assessment of these charges, which is currently assessed at 5.76% per year. This means that where customers are responsible for interconnection costs, they are charged once for the cost of upgrades, and then charged again in either a monthly or one time cumulative charge for future replacement and associated costs even when the equipment is expected to have a service life equal to or exceeding that of the customer’s DER facility. This practice effectively increases the cost of both interconnection facilities and required upgrades by 75.3%. Clean Coalition thus proposed that customers should not be charged for upgrades where no hardware is involved, such as changing the settings on load tap changers, contending that the issue of whether customer charges should reflect costs based on the term of service defined in the Interconnection Agreement is a relatively narrow question that can and should be easily resolved.

Smart Inverter Operational Requirements (Issue #27)

On December 19, 2018, a SIWG call was held on December 19 that began with an overview of the Phase 3 functions. Function 1, 5, 6, and 8 will become effective on February 22, 2019, though the deadline for Functions 1 and 8 is under discussion. Functions 4 and 7 are under discussion and will only become effective 12 months after NRTL approval. Functions 1 and 3 will become effective earlier of December 2019 or 12 months after approval of the IEEE 1547.1 standard revision. The IOUs explained that some of these functions are needed on an ad hoc basis today, though a blanket activation is not needed at this time, and that Rule 21 should allow for some of these functions to be activated by mutual agreement between the distribution provider and customer. The IOUs proposed to consider and discuss a circuit-level penetration threshold as a function of load or hosting capacity beyond which the IOUs will begin requiring blanket activation. CALSSA presented an issue overview that identified the goals to identify priority use cases of smart inverters, define procedures and rules for distribution services, and set target deployment of DERMs. DERs can provide voltage support as a routine management tool or in response to abnormal conditions, with smart inverters capable of providing Volt-Var, Volt-Watt, and fixed power factor (in place of Volt-Var). Thus, CALSSA proposed several use cases for an IDER tariff agreement that would be offered as part of the interconnection application:

• Change settings of voltage functions in response to feeder reconfiguration

• Schedule changes to settings of voltage functions to address seasonal differences

• Ongoing adjustments to settings of voltage functions in place of other voltage regulators

• Managed timing of DER restoration through smart inverter communications after a grid outage to avoid voltage spikes

Broadly, CALSSA tried to make the point that IOUs should also be required to deploy communications systems and capabilities (i.e., DERMS) similar to how DER customers are required to deploy such capabilities.

On January 31, 2019, the IOUs provided their initial feedback and explained that, prior to leveraging smart inverters for new grid services, the impact of residential default TOU rates need to be assessed, the level of smart inverter penetration must reach a certain threshold, communications need to exist and be activated, and DERMS need to be available and usable. SDG&E indicated that the autonomous settings required by February 22, 2019 should be sufficient in the near term. Based on their pilots, the IOUs indicated that smart inverters have addressed secondary voltage rise but had little impact at the primary level, where utility voltage management systems and strategies (e.g., regulators, capacitors) may be more effective. SCE was open to considering how smart inverters could be used for localized reactive power support and for DER disconnects.

Smart Inverter & IDER Coordination (Issue #28)

On December 19, 2019, a SIWG call was held where the IOUs presented their views on how smart inverter operational requirements could be defined within the IDER proceeding for specific functionalities required to serve a grid need. The non-IOU stakeholders, meanwhile, presented their views that requirements to utilize a 2030.5 communications channel should be introduced only once the market exists and customers can discern and compare the value of communications services.

Non-Export & Limited Export Parameters (Issue A)

On January 31, 2019, CALSSA introduced the issue of providing a clear option that allows projects to qualify as non-exporting, limited export, or inadvertent export using storage control systems, as Certification Requirements Decision (CRD) is being developed under 2020 NEC 705.13. Final approval will be received this month as an addendum to UL 1741. CALSSA and IREC thus proposed that Rule 21 recognize the new standard, where certified storage systems should be eligible for “inadvertent export” if its response time falls within the defined boundaries of Rule 21 and should be eligible for “limited export” if it has a fixed maximum export higher than zero. For both non-export and limited export, IOUs said that they need to look at customer behavior and study realistic scenarios for maximum export value and that they need validation that the inverter is initially set up properly. Non-IOU stakeholders expressed that CRD is the preferred certification system instead of a California-specific solution, but the IOUs wanted to maintain the option to adopt other approaches as well.

Solar+Storage Capacity Treatment (Issue B)

On January 31, 2019, CALSSA introduced the issue of solar-plus-storage systems being studied in the interconnection review process under the scenario of “nameplate plus nameplate” due to these combined systems not qualifying for non-export or inadvertent export. This is problematic if customers plan to set a controlled maximum value that is less than nameplate plus nameplate. CALSSA and IREC thus proposed to amend Rule 21 to accept a maximum export value (or limited export) for systems using equipment that is certified to the Power Control Systems CRD. Within 60 calendar days of completion of Phase 2 of the Power Control Systems CRD, they proposed that the IOUs issue an advice letter incorporating scheduled changes to maximum export values for solar and storage systems. The other recommendation is that the IOUs expressly identify that certified limited export projects will be studied according to the maximum export value for specified technical issues (i.e., not at nameplate value except for in cases of short-circuit duty contribution).

Binding Review & Studies (Issue D)

On February 6, 2019, stakeholders discussed what the appropriate cut-off time should be for getting billed actual costs. SCE and SDG&E did not support results of an initial review or detailed study being binding. This is because cost estimates performed in the initial review or detailed study are based on desktop evaluations that do not have sufficient technical and physical information to accurately determine cost. SDG&E also pointed to how a binding option would conflict with the existing cost envelope option pilot.

Working Group 4

Background

Working Group #4 focused on the following key issues:

• Issue 18: Should the CPUC adopt changes to anti-islanding screen parameters to reflect research on islanding risks when using UL 1741-certified inverters in order to avoid unnecessary mitigations? If yes, what should those changes entail?

• Issue 19: Should the CPUC adopt streamlined interconnection procedures (e.g. standard configurations eligible for expedited review) to facilitate implementation of California Zero Net Energy building codes and, if so, what should those procedures entail?

• Issue 29: Should the CPUC establish a forum, either within this proceeding or externally to develop interconnection safety standards to address safety and environmental risks as the interconnection of distributed energy resources devices grows?

• Issue F: What interconnection rules should the CPUC adopt to account for the ability of DERMS and aggregator commands to address operational flexibility need?

On November 27, 2019, a Ruling was issued that revised the Rule 21 proceeding to commence Working Group 4 in February 2020.

Anti-Islanding Screen (Issue #18)

Background

Distributed energy resources (DERs) require anti-islanding protections to ensure that they do not operate as an unintentional island exporting power to the grid when the distribution system is otherwise de-energized. UL 1741, the Rule 21 standard for all California interconnections, requires strict testing to ensure that inverters shut down production within two seconds of a grid outage.

Some research has shown in lab studies that anti-islanding controls can fail in certain conditions, which include proximity to large non-inverter-based machine generators, high power factor, and a high amount of generation compared to load. It is highly disputed how commonly these factors can occur. PG&E interconnection review contains a screen that tests for some of those conditions, in accordance with PG&E Technical Document TD-2306B-002. Interconnection review of SCE and SDG&E does not contain this type of screen.

Two mitigations being implemented by PG&E to manage the risk of islanding are reclosers at the distribution level and direct transfer trip (DTT) at the substation/transmission level. These mitigations ensure that the machine generators do not run on past two seconds after a grid fault or scheduled de-energization. The cost of installing direct transfer trip is approximately $800,000 and takes 18-24 months to complete. The cost of a recloser is typically $120,000 and takes 6-12 months to complete. These upgrades commonly force renewable DER projects to withdraw due to their heavy costs and long implementation timelines. There are also examples of mitigation costs borne by ratepayers for projects smaller than 1 MW.

There are three ratios that determine the level of risk on a circuit segment:

• a.) The ratio of total generation to minimum load

• b.) The ratio of machine generation to total generation

• c.) The ratio of reactive power to active power

A project currently fails PG&E’s screen if Ratio A is greater than 50% and Ratio B is greater than 40%. The screen does not include Ratio C. Currently, minimum load and total generation are calculated in Ratio A as annual values even though they are not consistent throughout the year. If the minimum daytime load is in December at 10:00 am and the maximum DER output is in June at 1:00 pm, those two values are used in the ratio even when the maximum DER output is far lower in December.

CALSSA Proposals

CALSSA believes that PG&E’s prescribed methods (using the Sandia screens) do not check for reactive power matching potential, leading to unnecessary mitigations for some projects (e.g., installation of reclosers or implementation of DTTs in areas where islanding cannot occur). Since most loads and power system components absorb VARs, there must be a source of VARs in the potential island in order for islanding to be sustained. This is slowing renewable energy development in California.

If it is not possible for the existing circuit to produce a power factor to match the DER being studied, the project should not require any additional risk of islanding screening or mitigations. For example, if a DER is set to operate at 0.99 power factor (pf), and the maximum load pf that can be achieved on the circuit is 0.92, the DER should not be subjected to mitigations because it is electrically impossible for the load pf to match the DER pf. As a result, CALSSA proposed the following:

• Proposal 18a (Protective Equipment Requirement for Machine Generators): CALSSA proposed that any machine generator larger than 40 kW requesting interconnection to the distribution system is required to install a recloser or other protective equipment of similar function and cost, unless the utility determines such equipment is unlikely to be necessary at any point in the future even after increased penetration of other generating resources on the circuit. This protective equipment should allow utilities to shut down the machine generator in the occurrence of a grid outage. Existing interconnections would not need to be retrofitted under this rule. This requirement should be revisited after three years if other mitigations with equal protection have become viable. CALSSA argued that this puts the anti-islanding protective burden on any new machine generator, rather than on other customers (distributed generators) subsequently connecting.

• Proposal 18b (Generation to Load Calculations): CALSSA proposed that the generation-to-load calculation should use the same temporal breakdown for load and PV generation as what is used in the ICA calculations. Utilities should determine that a project exceeds the screen threshold if the ratio of total generation to load exceeds 50% during any of the 288 hours. This calculation would not be performed as part of ICA updates for all locations. It would be performed for specific locations in response to individual interconnection applications. Applications for systems larger than 30 kW can be required to submit an hourly generation profile with the initial application so that the utility has the data when a calculation is needed. CALSSA argued that this creates a more accurate calculation that will result in fewer unnecessary mitigations being required.

• Proposal 18c (Independent Risk of Islanding Studies): CALSSA proposed that, if the utility determines that mitigation is required, the customer should have the option to hire an independent analyst to perform a risk of islanding study. This study would include analysis specific to the proposed installation and the circuit segment. If the risk of islanding study demonstrates that an islanding condition is not possible, the project should be allowed to interconnect with no mitigations for managing islanding beyond the existing UL 1741 certification. In addition to risk of islanding, alternative mitigation methods to DTT and reclosers should be explored in the study. This should include but not be limited to utilizing DERMS to mitigate islanding, utilizing additional protective devices and relays at the point of interconnection, and adjusting DER settings and production schedules so that real and reactive power matching is not possible. According to CALSSA, this proposal addresses the problem that the current anti-islanding screen is less accurate than an in-depth study. This proposal was supported by BAC.

In addition, the risk of islanding study should include alternative mitigation methods to DTT and reclosers, if any. This should include but not be limited to utilizing DERMS to mitigate islanding, utilizing additional protective devices and relays at the point of interconnection, and adjusting DER production schedules so that real and reactive power matching is not possible. The utilities can maintain a list of firms they deem qualified to perform risk of islanding studies.

PG&E Proposals

If an unintentional island is formed, the utility can no longer control power quality and thus wants to ensure that unintentional islands do not occur in the first place. On the technical side, reclosing into an energized island is one major risk since it can damage loads if done significantly out of phase. However, there are technical solutions such as synchronized reclosing or reclose blocking. When exploring system-level approaches to dealing with island risk, it may pay to question the assumptions that lead to mitigation in the first place. 

Currently, PG&E does not require mitigation if all the islanded DER consists of certified inverter-based generation. However, if there is machine based or uncertified generation within the island, mitigation may be required, it should be pointed out that as more certified inverters are added to the grid the less likely islanding mitigation will be required. In recognition of CALSSA's concerns, PG&E proposed the following changes:

• Proposal 18e (PG&E Anti-Islanding Screen): PG&E proposed to adopt a new anti-islanding screen that considers aggregate generation relative to minimum load, aggregate machine generation or aggregate uncertified DG to total generation ratio, fixed power factor modes, and inverter anti-islanding “types.” The proposed screen is used to verify or ensure islands are terminated in two seconds or less in accordance with Rule 21 Section H.1a.iii and section 4.b, whenever there is a question of whether a system configuration may result in an island lasting more than two seconds. The proposed screen is not binding on the other IOUs. This proposal is opposed by BAC.

PG&E argued that this proposal would create a potentially faster review process for inverters with Group 1 or 2A anti-islanding methods, which have been shown to be effective even when paired with fairly high proportions of rotating machines or other less effective anti-islanding methods. Such a screening process could provide impetus for developers to prefer those inverters, and thus create a market incentive for inverter manufacturers to utilize those methods.

IREC Proposals

Anti-islanding capability has always been tested on the individual inverter level per the test procedures of IEEE 1547.1, but it has been shown that interactions between inverters and rotating machines can decrease anti-islanding effectiveness and that some anti-islanding algorithms may be more effective than others.  It is now understood that the risks of unintentional island formation has less to do with any individual inverter (since all are certified to have adequate individual anti-islanding capabilities) and more to do with a variety of different types of interactions between equipment on the distribution system.  As a result, the Interstate Renewable Energy Council (IREC) explained that it is becoming clear that unintentional islanding is a distribution system issue, and yet individual inverters are being called on to address the issue. As a result, IREC proposed the following:

• Proposal 18d (Islanding Working Group): IREC proposed that the CPUC should organize an Islanding Working Group to explore and recommend next steps in the continuance of islanding (or anti-islanding) research and development at both the distribution and transmission system level.

While mitigating unintentional islanding has focused on the single DER/inverter up until now, mitigating island formation may also be done at the transmission or distribution system level (e.g., through the use of voltage reclose blocking, high-speed grounding switches, or a power line carrier heartbeat signal)  and could apply to all DER on the circuit.

BAC Proposals

California must remove barriers to bioenergy interconnection to meet the state’s climate goals. The Tree Mortality Task Force review of interconnection costs highlighted the enormous uncertainty that developers face when it comes to interconnection requirements and costs and the high variability from one utility expert to another. Providing clear, reliable guidance on which technologies will be required under what circumstances is critical to help small-scale bioenergy projects determine where to site projects to minimize interconnection costs and what costs to expect. Given this, the Bioenergy Association of California proposed the following:

• Proposal 18f (Interconnection Guidebook): BAC proposed that the CPUC, utilities, and developers should work together to develop a guide that provides anti-islanding options, clearly identifies the cost of each option, and sets out the circumstances when it will be required. Utilities should not be allowed to require more than what is in this “Interconnection Guidebook” unless they demonstrate the need for additional measures in a timely manner.

• Proposal 18g (Least-Cost Best Fit): BAC proposed that the utilities should be required to offer least-cost, best-fit solutions to meet anti-islanding requirements.

• Proposal 18h (Timelines for Small-Scale Bioenergy Projects Employing Synchronous Generators): BAC proposed that the CPUC should adopt an enforceable interconnection timeline so that small-scale bioenergy projects employing synchronous generators do not have to wait for extended periods of time after completion to connect to the grid.

• Proposal 18i (Funding Demonstrations and Guidebook): BAC proposed that the Working Group should support use of EPIC funding to identify and demonstrate additional, less expensive options for anti-islanding, help fund development of the Interconnection Guide, and help demonstrate technologies that provide anti-islanding and islanding (microgrid) solutions.

Circuit-level microgrids could eventually serve a resiliency role on feeders or substations with high DER penetration and coordination. Preparing for that future would mean reframing the discussion from anti-islanding to intentional islanding. Today’s DER equipment, with the focus on avoiding islands, may not be able to be integrated into a future microgrid. Microgrid-ready inverters may need a means to adjust functional parameters when entering microgrid mode.

New Zero Net Energy (ZNE) Construction (Issue #19)

Background

California’s new building code requires solar on all new residential construction as of January 1, 2020. The requirements are outlined in Title 24 (2019). Storage may be included to reduce the required amount of solar. Energy efficiency measures directly impact the required solar capacity. A ZNE building uses solar, storage, and energy efficiency measures to fully or partially offset energy consumption. The storage incorporated into ZNE residential buildings (NEM paired storage) could be non-exporting, only used for load reduction and peak shaving, or exporting, providing opportunities for system benefits with direct or indirect (i.e., TOU) approaches.

The interconnection review process was designed around the scenario of adding distributed energy resources (DERs) to existing properties. The traditional process is challenging for homes under initial construction. With solar requirements for new home construction as of January 1, 2020, the working group assessed potential hurdles for solar on new construction, including:

• While interconnection applications have traditionally been identified by meter number and service account number, a house under construction does not have a homeowner service account or meter.

• Solar installation should be part of the overall construction schedule.

Builders and homebuyers have experienced two common problems. If a homebuyer requests electrical service while the interconnection application is still pending, utilities have cancelled the application from the builder and required the homebuyer to submit a new application. Also, if the system is not given permission to operate before the homebuyer moves in, the system cannot be used, and the process is complicated because the builder is out of the picture.

The proposals put forth by the Working Group for Issue 19 are all intended to streamline interconnection procedures and timelines to facilitate implementation of California ZNE building codes. Historically, the interconnection review process was designed around the scenario of adding distributed energy resources (DERs) to existing properties.  Now that there is a state requirement that all new homes contain solar, it is important to remove unnecessary hurdles for solar on new construction.

CALSSA Application Streamlining Proposals

CALSSA developed several proposals to have the generation considered at the same time as the new load, rather than doing so sequentially (e.g., submitting interconnection application after receiving account numbers). These proposals are intended to accommodate construction schedules and streamline processes.

• Proposal 19a (Application from Builder Using Address): The builder should be able to submit an interconnection application in their name based on a street address. The meter number should not be required for an interconnection application for new construction. If a customer sets up service before the utility grants permission to operate the system, this should not impact the application that was signed by the builder before the transfer of ownership. Utilities should issue permission to operate before the homebuyer moves in except in extraordinary circumstances. CALSSA argued that this proposal aligns with ZNE new home construction schedules; it is known prior to construction that all homes will require interconnection.

• Proposal 19b (Community Applications): Builders of developments with multiple units should be able to submit a single application for all of the units. It is inefficient to submit and review individual interconnection applications when an entire subdivision is under development. Submitting applications piecemeal hinders the utility’s ability to plan for the entire community. The proposed implementation date is December 31, 2021.

• Proposal 19c (Standard Templates): Standard single-line diagrams (SLDs) should be developed for small solar, small solar-plus-storage, and apartment buildings with virtual net metering (VNEM), which can save time by not having to review site-specific designs for simple systems. Template SLDs for new ZNE residential construction will reduce the average time required for the deemed-complete process.

SCE and SDG&E are already compliant with Proposal 19a. By contrast, PG&E continues to require a homeowner account number and meter number in the interconnection application. CALSSA urged that PG&E should implement this proposal before December 31, 2021. Meanwhile, the IOUs argued that action on Proposal 19c should be contingent upon decisions taken in the microgrid proceeding, R.19-09-009. If SLDs are addressed in that proceeding, then this proposal is only necessary to the extent it covers SLDs for new ZNE residential construction that are not covered by decisions in the microgrid proceeding.

Clean Coalition Application Streamlining Proposal

Clean Coalition expressed that the use of standard templates should go beyond the narrow set of small solar and storage systems:

• Proposal 19-d (Standard Templates for Multiple Use Cases): All three IOUs should be required to publish standard proposed facility configuration designs and single line diagrams for use in new ZNE residential construction interconnection applications.

Specifically, Clean Coalition proposed that a standard design and SLD shall be published within 120 days for any category or sub-category of ZNE facilities in which at least 50 applications have been received in the past year, or as otherwise instructed by Energy Division. The template shall be published in one or more formats which provide the ability to enter information digitally and that is capable of being electronically submitted in a machine-readable format. Where applicable, utilities are encouraged to minimize duplication or inconsistency. As a result, all projects within each project category will be required to follow the same single line diagrams, which will reduce the total number of single line diagrams required.

PG&E and SDG&E responded that they already deploy standard SLDs for small NEM systems (less than or equal to 30 kW). SCE currently does not use a template diagram for any scenario but explained that it does publish examples.

GPI Automation Proposals

Green Power Institute (GPI) expressed that streamlining and automation options now present a more favorable cost/benefit ratio:

• Proposal 19-e (Automation): Utilities should fully consider and provide responses on the degree to which ZNE interconnection applications may enjoy the same or similar benefits as NEM projects under 30 kW currently enjoy in terms of rapid processing. Utilities should consider which of the expedited processing tools applicable to projects 30 kW and below can be extended to ZNE projects.

In order to distinguish ZNE interconnection applications, ZNE applications shall check the appropriate box on the interconnection application, indicating that they are ZNE applications. Certification of ZNE eligibility from the applicant will be required prior to PTO. Such certification procedures for ZNE buildings are described in Title 24. GPI focused on potential near-term options that could support streamlined and automated interconnection processes applicable to ZNE interconnection:

• Automating the application process and completeness review

• Automating (at least partially) Initial Review

• Automating (at least partially) Supplemental Review

• Frontloading Supplemental Review Screens N and O into Initial Review

• Combining Initial Review and Supplemental Review

• Frontloading and automating the Generator Interconnection Agreement (GIA) generation and offer process

Interconnection Safety Standards (Issue #29)

Background

As DERs reach higher levels of penetration and technology changes in the future, the CPUC asked the question of the various safety and environmental risks of interconnecting DERs and to identify gaps or shortcomings.

• Issue 29: Should the CPUC establish a forum, either within this proceeding or externally to develop interconnection safety standards to address safety and environmental risks as the interconnection of distributed energy resources devices grows?

CALSSA & Clean Coalition Procedural Proposal

CALSSA and Clean Coalition submitted a proposal that, nine months after completion of the Rule 21 Working Group 4 Report, the CPUC should issue a Ruling soliciting input on safety and environmental issues related to interconnection of DERs to be discussed in a future Rule 21 Working Group, or in another forum.

Working Group Development

Most working group participants have agreed that a separate or new type of forum to address safety and environment issues related to interconnection of DERs is not needed because the current Rule 21 working group meets the needs suggested by this issue. Rule 21 is a safety standard and its fundamental purpose is to have interconnection safety standards that can guide the growth of DERs.

Distributed Energy Resource Management Systems (Issue F)

Background

During working group meetings in 2016-2017, participants developed the methodology for the Integration Capacity Analysis (ICA) and agreed that the ICA should be based on five constraints: thermal limits, steady-state voltage, voltage fluctuation, protection, and operational flexibility. The operational flexibility constraint captures the need for flexibility to reconfigure circuits during maintenance or unplanned outages. Because customers sometimes get switched to adjacent circuits, the impact of a distributed energy resource (DER) on circuits that they might be connected to must be studied, even if they are not connected to those circuits in normal circumstances.

Participants did not come up with a methodology for doing an advance calculation of this constraint that was not highly restrictive. When an actual project is studied, utility engineers take into account the likelihood of being connected to an adjacent circuit, the availability of other switching options, and the extent of the risk if a DER is connected to the circuit in question. The utilities did not come up with a way that these factors could be applied objectively and accurately across the grid in the ICA calculations. The utilities proposed that the threshold of the operational flexibility constraint should be the DER size above which power could backfeed across a SCADA-controlled switching device. Non-utility stakeholders reluctant agreed to support the proposal as an interim methodology.

One possible solution to this restriction could be that utility may in the future utilize communication means to send commands directly to DER systems or may send communication through third-party aggregators to DER systems as to mitigate the issues related to operational flexibility. However, that capability will only be available after the CPUC develops rules for contractual relationships between utilities and DER system owners through a stakeholder process, or such contracts are found mutually agreeable to counterparties and do not violate existing regulations. Another possible solution is through the implementation of future Distributed Energy Resource Management Systems (DERMS), which would provide high levels of visibility and control and would mitigate the system flexibility limitation.

In this period when utilities are finalizing their plans for rolling out DERMS, the Working Group is tasked with developing rules for how DERMS will be applied to the operational flexibility ICA constraint. Beyond the technical capabilities, there must be a standard contractual relationship between utilities and customers wishing to use this functionality. Compliance with the requirement will be determined at the inverter level. An inverter model only needs to be certified that it communicates correctly in combination with one gateway. It can then be interconnected with other gateways with which it has not been certified. In cases where a customer elects to use smart inverter functionality to address the operational flexibility constraint and the inverter/gateway combination has not been certified, it is reasonable for the utility to require that the customer demonstrate functionality in a commissioning test.

CALSSA Application Streamlining Proposals

CALSSA developed several proposals:

• Operational flexibility provisions in Rule 21: The operational flexibility ICA constraint is severely limiting for many locations even if circuit reconfigurations at that location are rare. This leads to underutilization of existing hosting capacity that has been paid for by ratepayers. As such, CALSSA proposed that the IOU shall make available an option for the project to be evaluated according to the ICA values without operational flexibility constraints if the interconnection agreement contains a provision for the project to address the constraint. The provision may include limiting or eliminating exported energy during defined periods or abnormal grid configurations and may include modifying advanced inverter functions. The provision shall contain terms for the maximum number and extent of curtailments, notifications to the customer about potential and actual curtailments, and any consequences for violations of the agreement by the customer or the distribution provider.

• Aggregator agreement: Smart inverter functionality can solve grid integration challenges, but some use cases may require contractual terms. CALSSA proposed that projects that communicate with utilities through a third-party aggregator must have a signed aggregator agreement.

• Demonstration of capabilities: The current compliance pathway does not test for all possible inverter-gateway combinations. As a condition of participation, the utilities may require a field demonstration of communications and functional performance of the system if neither the inverter nor the inverter-gateway combination has received the relevant certification from a nationally recognized testing laboratory (NRTL).

Public Advocates Office (PAO) Proposal

PAO submitted a proposal that argued that the CPUC has promulgated smart inverter requirements that have only applied to inverter manufacturers, not IOUs. Realization of smart inverter benefits requires the CPUC to order the IOUs to take specific actions by specific dates, just as it has done for smart inverter manufacturers in the Rule 21 proceeding. The history of smart inverters in California shows that mandated deadlines are often the starting point, rather than the end point, for operationalization of new systems and tools. To this end, the PAO recommended that the CPUC should set deadlines for the IOUs to be able to monitor and control DERs and should establish an accelerated process and schedule to develop rules for IOU utilization of Phase 3 control functions that can aid DER integration, including OpFlex.

Working Group Development

On April 8, 2020, a workshop was held to discuss proposals from CALSSA and to have SolarEdge and Tesla share their DERMS experience from other jurisdictions to provide operational flexibility. While residential aggregators use existing telecommunications networks to talk to DERs, homeowners connect the DER to the ethernet or cellular devices. Aggregators do not own or operate these networks and network devices. Smart inverters are well positioned to provide the required systematic flexibilities since no gateways are required and communications are built in. SolarEdge argued that there is no need to wait for DERMS, as the utilities can pilot smart inverter functions today. The IOUs also provided description of their DERMS-related activity.

Smart Inverter Working Group

Background

Generating resources interconnecting to the utility grid via Rule 21, which produce direct current (DC) power, require an inverter to convert the DC from the generating resource to the voltage and frequency of the alternating current (AC) distribution system. A smart inverter may mitigate some of the adverse grid impacts of distributed energy resources (DERs), enable greater penetration of DERs, and enhance the value of DERs by enabling grid services. 

On September 22, 2011, the CPUC initiated R.11-09-011 and established the SIWG in early 2013 to develop proposals to take advantage of the new, rapidly advancing technical capabilities of inverters. The SIWG was tasked with making technical feasibility assessments and recommendations (not discuss compensation mechanisms). Smart inverters were defined in the SIWG as inverters that perform functions when activated that can autonomously contribute to grid support during excursions from normal operating voltage and frequency conditions. They can do this by providing dynamic real/reactive power support, voltage/frequency ride-through, ramp rate controls, and communication systems with the ability to accept external commands, among other functions. 

Distributed Energy Resource Management Systems (DERMS)

On February 13, 2019, the IOUs presented an update on their DERMS efforts, including resources from EPRI, PG&E, and SEPA. The IOUs discussed how the many complex functions of smart inverters coupled with their continuously-variable settings results in an infinite number of potential settings and multiple ways to achieve similar outcomes. Distribution Management System (DMS) algorithms are concerned with the net effect of such settings on the grid, not the specific functions or settings used to achieve the effect. DERMS are thus intended to create a flexible means to aggregate DER into groups by which they can be viewed and managed collectively. Importantly, power system management systems need services provided in a stable, sustained fashion. Because many DER are variable (e.g., solar), achieving this involves intelligence, and potentially frequent adjustment of device settings to maintain targets set for DER groups. Consistent behaviors to be implemented and provided by DERMS and device providers are expected to be understood and utilized by DMS systems. Similarly, consistent communication encodings that allow system components from multiple vendors to be integrated are needed without requiring custom mapping software for each.

The IOUs explained that the DMS determines what service is needed while DERMS provides the service as requested. A DERMS may not understand why a given set of DER have been organized into a dispatchable group and likely would not know why a given service is being requested at a given time. The DMS is the part that knows why. DMS has visibility to sensors on the power system, understands it present status and limitations and knows what the operational goals and priorities are at any given time. However, a DERMS system must be able to optimize the available resources within the dispatchable group to provide the requested service.

According to SEPA, some key DERMS requirements include the following:

• Awareness of DER Real-Time Circuit Topology Connections: DERMS shall include a circuit model of the electric distribution system to which each asset is attached. DERMS shall include a suitable mechanism to build and maintain this model, such as via an interface between the DERMS and the local utility company’s Geospatial Information System (GIS). DERMS visibility into the distribution system model could also be achieved via tight integration with DMS/ADMS).

• Interconnection Agreements Contractual Awareness: DERMS shall be able to import the AC nameplate data from an external system per user-defined requirements, such as those established by a state regulatory agency. DERMS shall be able to enforce operating power factor requirements from technical studies which are written into the contract.

• Support Real Power Operating Modes: DERMS shall be able to dispatch available DER assets in a manner that limits the load on a specified substation to a given value over a given time period.

• DER Constraint Management Communications Monitoring & Processing: DERMS shall support a heartbeat function to monitor communication connectivity to the end device.

PG&E presented on the key takeaways from its EPIC 2.02 DERMS Demonstration. While DERMS vendors exhibited capabilities in certain aspects of a DERMS, there was no vendor capable of the comprehensive DERMS system PG&E envisions at this time. PG&E needs to invest in foundational technology including improved data quality, modeling, forecasting, communications, cybersecurity, and a DER-aware ADMS to address the near-term impacts of DERs and grid complexity while providing the groundwork for a future DERMS system. DERs must provide sufficient locational value, volume, availability, and dispatch assurance to offer grid services. DERMS capabilities could be enabled on an as-needed basis at constrained distribution locations. In other words, targeted DERMS deployments to address local distribution constraints may be more cost-effective than a fully automated, ADMS-integrated DERMS deployed across the entire distribution system. Overall though, PG&E believes that unified standards, protocols, testing, and exchanges are needed as DERMS requirements and market structures become more defined. Importantly, PG&E emphasized that, to preserve distribution safety and reliability, distribution dispatch must have priority over wholesale market operations and visibility across both systems.

SIWG Phase 1

Background

Phase 1 of the SIWG developed seven autonomous inverter functions, adopted in D.14-12-035, that became mandatory for all inverter-connected DERs on September 8, 2017. These autonomous functions include:

• High/low voltage ride-through

• High/low frequency ride-through

• Dynamic Volt/VAR operation

• Ramp rate controls

• Reconnect by "soft start"

• Fixed power factor

• Anti-islanding

Policy Development

On December 18, 2014, D.14-12-035 was issued that ordered the IOUs to implement the Phase 1 requirements, which included dynamic Volt-VAR operation applying active power priority.

On September 8, 2016, the Underwriters Laboratory (UL) announced the approval of the new UL 1741 Supplement SA to test and certify inverters and other utility interconnected distributed generation equipment for grid support functions enabling smart and safer reactive grid interconnection.

On September 13, 2016, each of the IOUs filed Advice Letters seeking to modify Rule 21 to require inverter-based generators to use smart inverters in order to interconnect under Rule 21, starting on September 8, 2017. These mandatory requirements are intended to comply with D.14-12-035 and are in line with the 2014 recommendations from the SIWG.

On September 8, 2017, all new interconnection applications for inverter-based generating facilities, including inverter-based storage facilities, interconnecting under the Rule 21 are required to utilize UL 1741 Supplemental A (SA) certified inverters. Non-exporting storage facilities are not exempted from this requirement. For stakeholders interested in DER aggregations, they objected to the adoption of the communication and scheduling capability requirements at this time. 

On July 27, 2017, the CPUC Energy Division issued a Staff Proposal that proposed how all grid-connected inverters can be transitioned from real power to reactive power priority to meet the required reactive power ranges and maintain voltages on feeders within their normal ranges. If voltage is low, smart inverters will be required to provide reactive power, and if voltage is high, smart inverters will be required to absorb reactive power. Reduction of real power production is allowed to meet the required reactive power ranges.

On December 29, 2017, each of the IOUs submitted advice letters on the reactive power priority setting of smart inverters. Several parties (SEIA, CALSEIA, IREC, and Sunrun) protested the advice letters because of the lack of analysis on activating this default setting that would curtail production, the potential to lead to oversizing inverters to account for these reactive power requirements, and the conflicts with soon-to-be-adopted IEEE 1547 standard. Rather, these parties generally seek activation of these curtailment-based capabilities in order to provide greater time for study on the frequency and unpredictability of localized curtailment and development of a compensation mechanism.

On March 27, 2018, the CPUC issued Draft Resolution E-4920 that incorporated the activation of the reactive power priority setting for smart inverters. Sunrun submitted a protest because it viewed these settings as effectively order the IOUs to curtail BTM DERs to address voltage issues. Sunrun believed that the use of reactive power priority is appropriately only after an interconnection review determines a specific customer that will cause that issue, consumer protection provisions are put in place, and compensation is provided for the grid services such functions provide. In particular, Sunrun had concerns that inverters with reactive power priority will activate Volt-Var and any associated curtailment within the IOUs' service range for voltage and will cost residential customers up to $3,500 in investments for these settings. 

SIWG Phase 2

Background

Phase 2 requirements delineate what communications capabilities are required for interconnecting inverter-based generating facilities. Phase 2 of the SIWG outlined the default communication protocols that govern how IOUs communicate with individual DERs and DER aggregators. In February 2015, the SIWG outlined three methods available: (1) distribution provider to the generating facility; (2) through GFEMS; and (3) through aggregator. Phase 2 requirements default to the IEEE 2030.5 communications standard (Smart Energy Profile 2.0 [SEP 2]), which defines a framework for communications between the utility and the generating resource, and were adopted on April 7, 2017 by Resolution E-4832.

Policy Development

On November 17, 2016, the SIWG held a workshop to discuss the implementation of Phase 2 and Phase 3 recommendations. The workshop discussed several Phase 3 issues, including key DER data monitoring situations, DER "cease to energize" situations, maximum real power mode limits, frequency-watt emergency modes, cybersecurity requirements, and more. Many of these technical issues have cross-overs with the existing IEEE 1547 requirements, and the question in the workshop was whether to adopt and/or refine similar requirements for California's Rule 21 tariff.

On December 20, 2016, the IOUs each filed Tier 3 Advice Letters to revise Rule 21 that incorporates the technical requirement changes that implemented Phase 2 and Phase 3 recommendations in compliance with D.16-06-052. These revisions included agreed-upon technical requirements, testing and certification processes, and effective dates for Phase 2 communication protocols and Phase 3 additional advanced inverter functions. In the absence of consensus, the IOUs were required to file a status report and work plan.

On April 7, 2017, Resolution E-4832 was approved that incorporated the SIWG’s Phase 2 recommendations on communication standards as Rule 21 tariff revisions. These standards would become requirements for generating facilities utilizing inverter-based technologies. The recommendations define the communications capability of smart inverters, specified pathways of communication between the utility and the generating facility, and the default communication protocol standard. The mandatory date for Phase 2 functionality for each of the IOUs is the later of: (a) March 1, 2018, or (b) nine month after the release of the SunSpec Alliance communication protocol certification test standard (or the release of another industry-recognized communication protocol certification test standard). Meanwhile, the CPUC and CEC are still working with the SIWG to reach a consensus on outstanding issues related to the Phase 3 functions and the SIWG’s recommendation on synchronization with the IEEE 1547 standard, such that the IOUs may file Tier 3 Advice Letters in June 2017 proposing tariff revisions to Rule 21.

On May 22, 2018, the SunSpec Alliance released its test procedure, which established the compliance date for generating facilities as February 22, 2019. The CSIP specification provides two connection scenarios:

• The IEEE 2030.5 interface is located onsite. The interface may be integrated in the DER or external to the DER. If the interface is external to the DER, the communication path between the IEEE 2030.5 interface and the DER is out of scope.

• The IEEE 2030.5 interface is located off-site in an aggregator. The communications path between the aggregator and DER is out of scope.

As allowed by the IEEE 2030.5 standard, the CSIP document states that an aggregator acting for the DER shall be able to store the required scheduling events. Inverters must be capable of communicating information and settings for the following functions: monitor key data, disconnect and reconnect, limit maximum power, frequency-watt mode, volt-watt mode, and support of volt-var, fixed power factor, and volt-watt through scheduling. Communication testing requirements should be mandated at interfaces only and the test procedures verify protocol compliance but do not verify electrical functional behavior. 

On September 20, 2018, the SIWG discussed Phase 2 and 3 implementation for smart inverters with and without an energy management system (EMS) or aggregator. However, SunSpec Alliance discussed the challenge of how end-to-end communication requirements are not yet fully stated in two of the three CSIP deployment scenarios and how no standard exists for aggregator to proprietary client protocol communication, placing burden on the combination of aggregator and client to perform testing.

On September 27, 2018, the SIWG had a meeting on software and hardware update certification as well as the requirements to demonstrate DER and aggregator communication capability. Stem presented at this meeting about how recertification processes can be expensive and time-consuming and thus led a discussion on how these recertification processes can be minimized or avoided due to software changes to an IEEE 2030.5 gateway (i.e., SunSpec) or firmware changes (i.e., UL 1741, IEEE 1547). Specifically, Stem proposed two possible pathways: (1) using a dual processor architecture (low-voltage DC, high-voltage AC); and (2) using a single processor. Stem also discussed how recertification for inverter firmware updates may be avoided or minimized if they are UL-1998 certified.

On October 18, 2018, the SIWG held a conference call to discuss IREC’s proposal for communication capabilities and verification and CALSSA’s proposal for Phase 2 compliance options. IREC argued that the Phase 2 rules require monitoring and controls but does not have an explicit requirement for certification. The SunSpec CSIP will verify aggregator, EMS, and SICU compliance but this is not necessarily needed by February 22, 2019 since the IOU will not be communicating via IEEE 2030.5. Since there is no market for IEEE 2030.5, not all inverters will be compliant directly, leading IREC to recommend either allowing for CSIP testing to check for capabilities (but not performance) or allowing vendors or manufacturers to verify these capabilities. CALSSA presented on how inverter manufacturers have mostly incorporated functionality to monitor key data (e.g., kWh, battery state of charge) due to demand for such features by DER developers and customers, so DER providers are willing to develop a test to verify this capability in a format other than IEEE 2030.5 before completion of IEEE 1547.1, but not for a February 22, 2019 deadline. On scheduling and adjusting set points (e.g., for Volt-VAR), CALSSA recommended that the IOUs accept a manufacturer declaration until IEEE 1547.1 is available as the test since there is no test for this capability at the moment. If manufacturers misrepresent this functionality, they should be removed from the CEC listing. Notably, CALSSA said that inverter manufacturers have been in a holding pattern due to uncertainty regarding how to demonstrate compliance with CSIP testing. Instead, CALSSA recommended moving the compliance date to May 22, 2019.

On October 25, 2018, SunSpec presented on how their informational models are being updated to map onto and harmonize with IEEE 1547-2018 interoperability requirements.

On January 3, 2019, the CPUC issued a letter that extended the deadline by six months from February 22, 2019 to August 22, 2019 to comply with Phase 2 communication requirements and with Phase 3 Functions 1 and 8. The CPUC agreed with the extension request from CALSSA, who justified the request based on the gaps in the certification regime (e.g., CSIP procedures do not provide for end-to-end testing). The CSIP was found to have significant gaps in testing and certification needs of industry and utilities, and the IOUs compounded the complex implementation problem with a late release of implementation plans.

On February 11, 2019, CALSSA filed a PFM of Resolutions E-4832 and E-4898 that requested that the CPUC direct the IOUs to file advice letters reflecting details of compliance that have consensus, including that IEEE 2030.5 certification should not be required at the inverter level, and that the CPUC extend the deadline (e.g., by 4-6 months) for Phase 2 communication requirements and Phase 3 Functions 1 and 8 beyond the current August 22, 2019 deadline, which was already extended once by the CPUC from February 22, 2019. CALSSA also requested that utility testing be eliminated and that utilities should rely on “compatibility testing” by NRTLs via inverter type-testing for Phase 2 requirements and on attestations for Phase 3 Functions 1 and 8 since these are testing for interoperability. Overall, the argument was made that requiring capabilities before requiring operation carries the risk of the requirements being out of step with what is fair to customers or practical in the marketplace. The three largest flaws in the implementation plans were highlighted as the following:

• SDG&E’s plan requires functionality at the inverter level that is inconsistent with agreements of the SIWG and IEEE.

• SDG&E’s plan requires undefined, utility-led testing that is inconsistent with agreements to rely on testing developed by the SunSpec Alliance. PG&E’s plan states that the utility may later decide to require such testing.

• The IOU plans require active contracts or installed equipment that are beyond the level of stakeholder agreement.

On February 20, 2019, the IOUs submitted a supplemental advice letter that proposed a delay of the Phase 2 certification requirement date until 12 months after IEEE 1547.1 is approved since its certification testing will resolve the issues raised about end-to-end testing and utility requirements to conduct their own end-to-end testing and Phase 3 functional certification. Several vendors disagreed with the IOUs’ proposal because it would risk failure to achieve the state’s goals, reduce confidence in the Rule 21 compliance dates, and penalize vendors who have made good-faith investments to meet the August 22, 2019 deadline.

On March 18, 2019, the IOUs responded to the PFM as supporting a more prolonged extension of the deadline for Phase 2 communication requirements and Phase 3 Functions 1 and 8 until the release of IEEE 1547.1, which will establish a full end-to-end testing standard (that is currently lacking) and is expected to be finalized by the end of 2019 or early 2020. They generally supported the use of the IEEE 2030.5 communication standard and the need to finalize an aggregator agreement but disputed the applicability of the SunSpec Alliance’s CSIP and CSIP Test Procedures, which is not intended to be a policy guide for all end-to-end communications and does not test communications between smart inverters and an IEEE 2030.5 certified gateway. SDG&E noted that the CSIP document was released in March 2018, eleven months after the CPUC adopted Resolution E-4832, which determined the policy for how generating facilities will be required to comply with communication protocols. The IOUs disagreed with CALSSA’s request to eliminate utility testing, though SCE was amenable to attestation to validate the performance of smart inverters in response to a communicated command (but not for the actual communications between smart inverters and the IEEE 2030.5 certified gateway). At a high level, the IOUs cautioned against deploying smart inverters without the appropriate testing and certifications that would increase the risk that incremental smart inverter deployments today would not be able to provide the services that the CPUC envisions in the future, potentially leading to costly retrofits and successive certifications and testing. However, in response, CALSSA conveyed that the question remains whether systems installed today will be able to participate in aggregated grid services in the future.

On April 29, 2019, the CPUC commented that it is exploring the harmonization of the compliance deadlines for Phase 3 Functions 2 and 3 with those for Phase 2 requirements and Phase 3 Functions 1 and 8. SunSpec clarified that IEEE 1547.1 will provide testing requirements for both the communication and electrical requirements when it is published:

• Must test at least one of the three specified standard protocols (IEEE 2030.5, SunSpec ModBus, IEEE 1815) at the physical DER communications interface

• Must only show that all adjustable settings specified in IEEE 1547-2018 are supported through the communications interface and elicit the required functional behavior in the DER

Several parties commented on the impracticality of end-to-end testing of projects with a high number of individual components (e.g., solar farm with many inverters) or projects with every possible equipment model, leading to manufacturer attestation as a preferable approach. CALSSA particularly disputed the IOU’s recommendation to require one industry standard (IEEE 2030.5) as the default protocol over another (SunSpec ModBus) and reiterated its view that a customer may use one of the other protocols at the DER interface as long as it is translated to IEEE 2030.5 by a gateway, which is an option in IEEE 1547-2018. CALSSA also highlighted the issue of manufacturers racing to meet a California-specific policy prior to the implementation of a national standard, so delays in this way are detrimental to the investments made.

On June 6, 2019, Draft Resolution E-5000 was issued that approved with modifications CALSSA’s PFM of Resolution E-4832 and Resolution E-4898 related to Phase 2 requirements and Phase 3 Functions 1 and 8. In comments, many parties were supportive, including IREC, SunSpec, and the IOUs. However, while supporting the harmonization of the timelines for the aforementioned requirements along with Phase 3 Functions 2 and 3, SCE recommended that the five-month extension to the compliance deadline (January 22, 2020) be extended further to 12 months after approval of IEEE 1547.1, which aligns with their expectation of smart inverter deployment and of SCE’s grid modernization programs and tools that enable them to receive communication functions. PG&E also requested clarification that attestation would be acceptable within 12 months of IEEE 1547.1 is published and that communications-capable inverter can use EMS or aggregator service instead of installed gateways or active contracts.

On July 12, 2019, the CPUC issued Resolution E-5000 that reaffirmed that the Phase 2 communications requirements may be met by any of the four options prescribed in Rule 21 Section Hh.5 and clarified that the Phase 2 requirements do not require IEEE 2030.5 capabilities at the inverter level. Additionally, it ordered PG&E, SCE, and SDG&E to adopt the testing pathway laid out by the Petition as the primary method of determining compliance with the Phase 2 requirements and clarified that the communications capabilities mandated by the Phase 2 requirements are limited to technical capabilities.

On August 9, 2019, each of the IOUs submitted advice letters that clarified that allowance of aggregator use of Section Hh.5 is subject to CPUC approval of applicable forms and agreement not currently developed.

On September 19, 2019, SIWG participants discussed attestations and which type of manufacturer (gateway or inverter manufacturer) should make the different attestations. CALSSA expressed that its understanding that the inverter manufacturer should make the attestation related to the inverter performance for Functions 1 and 8. CALSSA believes that the Phase 2 communication attestation should be acceptable from either the gateway manufacturer or the inverter manufacturer.

On October 9, 2019, CALSSA submitted a clarification request on the approved testing pathway for the Phase 2 communication requirements. Specifically, CALSSA requested that the CPUC amend Resolution E-5000 as follows:

• Because Appendix C only concerns Phase 2 communications, “executes the commands” means that the inverter communicated a proper response. A separate attestation on inverters changing settings in response to a communication will come from the inverter manufacturer.

• The Phase 2 requirement can originate from the inverter manufacturer and be submitted by the gateway manufacturer if the gateway manufacturer does not originate the attestation itself.

In addition, CALSSA expressed how accurately describing categories of devices is challenging because different terms are used in Rule 21, CSIP, and IEEE. CALSSA attempted to use the term “gateway” as referring to both off-site aggregators and on-site energy management systems, but reference to an “inverter control unit” seems to have created confusion. Per Rule 21, an inverter that does not use IEEE 2030.5 internally can satisfy the requirement for communications capabilities by communicating with an on-site device or an off-site aggregator that translates a signal to IEEE 2030.5. As a result, CALSSA requested that the CPUC adopt the “gateway” definition as follows: “Anything other than the DER that provides a communications interface (CSIP/IEEE 2030.5) to the utility for the purposes of exchanging the content contained in the communications messages with one or more DERs.”

In response, SCE proposed deleting the term “inverter control unit” (ICU) from Appendix C because it is not a defined term in Rule 21, was observed as creating confusion among stakeholders, and was duplicative of the “gateway” term.

On November 21, 2019, CALSSA requested a two-month extension of the deadline to comply with the Phase 2 communication requirements and with Phase 3 Functions 1, 2, 3, and 8 from January 22, 2020 to March 22, 2020. The CPUC granted the extension request because additional time will provide industry more opportunity to adapt to the smart inverter requirements while avoiding market disruption.

On December 19, 2019, Resolution E-5036 was issued that clarified that, either the inverter manufacturer or the gateway manufacturer must attest that the inverter communicates with the NRTL server and executes the command. Second, this Resolution adopted the definition of the technical term “gateway,” as used in Resolution E-5000, that is offered by CALSSA: “Anything other than the DER that provides a communications interface (CSIP/IEEE 2030.5) to the utility for the purposes of exchanging the content contained in the communications messages with one or more DERs.” Third, this Resolution adopted a redline of Resolution E-5000’s Appendix C that reflects the clarifications adopted herein. Additionally, this Resolution corrected a typographical error in Resolution E-5000 and reaffirmed that the PG&E, SCE, and SDG&E must accept manufacturer attestations as sufficient evidence of compliance with Phase 3 Function 1 (Monitor Key Data) until 18 months after the publication of a nationally-recognized test procedure containing that function.

On March 17, 2020, Fronius USA and Ginlong Solis USA requested a four-month extension of the deadline to comply with the Smart Inverter Phase 2 communication requirements and with Phase 3 Functions 1, 2, 3, and 8 due to travel restrictions put in place in response to the COVID-19 pandemic. The CPUC granted the extension from the current deadline (March 22, 2020) to June 22, 2020 and the IOUs submitted advice letters accordingly.

On May 21, 2020, the IEEE 1547.1-2020 was officially published as the national standard for key smart inverter functionalities of DERs and validates with standard communication interfaces by naming the IEEE 2030.5-2018 protocol as the default DER-to-utility communication protocol chosen by California. During the July 23 meeting, SIWG kicked off its efforts to map the changes to against existing Rule 21 requirements and to determine where harmonization in necessary. The publication of IEEE 1547.1-2020 triggered an update to the Rule 21 tariff via an advice letter filing within 9 months to reflect this new standard and set the schedule for the start of a new Cybersecurity Working Group that was scheduled to meet within 90 days of publication (August 13, 2020). The SunSpec Modbus was also established as an option for meeting the IEEE 1547 data communication requirements at the device level.

SIWG Phase 3

Background

Phase 3 of the SIWG developed recommendations for additional advanced functions that enable operational protocols or transactional models to provide inverter-based DER grid services. The SIWG submitted its Phase 3 recommendations in March 2016 and updated its recommendations in March 2017. These advanced functions represent a higher, more forward-looking level of DER monitoring and control, in which DERs can be leveraged via Phase 2 communications to provide a material response to certain grid conditions. These eight advanced functions include:

• Function 1: Monitor Key DER Data: The inverter takes measurements as it converts power. With the ability to communicate, the inverter or aggregator can send this information, such as voltage and active and reactive power, to the utility. Required data types are listed in CSIP Table 2.

• Function 2: DER Disconnect and Reconnect Command (Cease to Energize and Return to Service): In certain situations, the utility may need to de-energize circuits to perform maintenance or repairs, or to prevent unsafe conditions during an emergency. With this function, the utility can send a command to the inverter to disconnect the DER from the local electrical system or prevent the DER from energizing the local system.

• Function 3: Limit Maximum Active Power Mode: This function establishes an upper limit on active power that a DER or system of DERs can produce or use. By limiting active power, this function helps to prevent adverse voltage conditions on the distribution grid and other related issues, especially in high DER penetration areas.

• Function 4: Set Active Power Mode: Similar to the previous function, this function establishes the active power that a DER or a system of DERs can produce or use.

• Function 5: Frequency-Watt Mode: As a system-wide parameter, frequency is affected by all devices connected to the electric power system. High frequency events are often a sign of too much power in the grid and vice versa. Frequency-Watt Mode is one method for countering these events, which is accomplished by reducing power in response to rising frequency or vice versa.

• Function 6: Volt-Watt Mode: As a general rule, the production of active power raises voltage. Volt-Watt Mode modifies active power from DERs based on pre-determined voltage ranges to prevent the local voltage on the distribution circuit from rising/dropping outside of allowable levels.

• Function 7: Dynamic Reactive Support: This function is similar to the Volt-Var Function from Phase 1. However, instead of modifying reactive power in response to the steady-state voltage level, this function responds to the rate of change in voltage.

• Function 8: Scheduling Power Values and Models: This function enables scheduling of active and reactive power, as well as modification of settings of other functions.

Policy Development

On August 17-18, 2017, the IOUs filed advice letters that modify each of their Rule 21 tariffs to reflect the following Phase 3 functions:

Many of the above changes will take effect 9-12 months after approvals of either the advice letters, IEEE 1547.1 standard, or Sunspec Alliance approved test procedures – i.e., in Q2 or Q3 2018. For smart inverters that include one or multiple energy storage systems, the available kWh energy will need to be communicated as an aggregate of all the energy storage systems.

On September 6, 2017, multiple protests were filed mainly due to the IOUs requiring the activation of Phase 3 functions (rather than setting requirements for these capabilities) and because it is premature to require these functions without any determination on how these functions would be compensated. Concerns were raised on the unnecessary PV curtailment risks of the proposed Volt-Watt and Frequency-Watt modes, on the California-specific nature of scheduling standards that may inhibit California’s inverter market, and on the complexity of staggered product releases of these functionalities. Given the number of concerns raised, a workshop will be held on October 25 to confirm areas of consensus and propose next steps.

On October 1, 2018, each of the IOUs filed advice letters that proposed to a methodology and report on the number and duration of voltage excursion events on the distribution system due to the activation of Function 6 (Volt-Watt) – i.e., curtailment when voltage exceeds 106%. While following their established processes to resolve voltage issues, the IOUs proposed to perform an estimation of energy losses using up to one year’s worth of AMI data and with the assumption that the DER system is able to produce at full output based on PV Watts and that the Volt-Var curve has no effect to energy reduction. No more than 20 customers per year will be subject to proactive energy loss estimation. Sunrun protested the advice letters on the basis of consumer protections because the IOUs’ proposal would not account for localized impacts (due to reliance on overall system average voltage excursions) and would not identify whether voltage excursions are due to utility infrastructure or DER output; instead, Sunrun recommended that the IOUs proactively monitor, collect, report, and respond to voltage excursions from smart meter data rather than relying on customer complaints for their curtailment assessments. IREC also protested the advice letters because of the lack of sufficient detail around AMI capabilities, referenced PVWatts profiles, and the voltage complaint process report. The IOUs generally responded that current AMI is unable to capture voltage data.

On October 1, 2018, the IOUs filed advice letters pursuant to Resolution E-4920 that argued that a monitoring and reporting framework specific to Volt-Var with reactive power priority is not practical since they cannot tell how much is being curtailed from the IOUs’ meters, which is located at the PCC, not behind the meter at the customer’s inverter, and would yield different results due to voltage drops in the line. The IOUs added that the presence of other DERs can affect the voltage the IOUs measure and obscure the impact of the DER inverter under consideration, the amount of generation produced by the solar generation is unknown beforehand, and curtailment can only happen if the inverter size is smaller than the max current generator output. The IOUs also distinguished how Volt-Var is distinct from Volt-Watt, which is more easily measurable and monitorable. Sunrun protested the advice letter on the grounds that the IOUs did not study customer impacts altogether and should proactively work with stakeholders to determine a path to monitor and report on the effects of activating the Volt-Var priority setting. The CPUC proceeded to suspend the advice letters on November 1, 2018, until further notice.

On October 11, 2018, the SIWG met to discuss potential technical specifications to meet the use case for each of the functions. Function 4 use cases could include providing real-time support to the local customer or local distribution grid and providing market/system support. Function 7 use cases could include minimizing flicker caused by intermittent DER operations or load fluctuations and providing transmission system support. All technical specifications would need to be discussed as part of an update to IEEE 1547-2018, so stakeholders generally agreed that no revisions or updates to the Rule 21 tariff be initiated at this time to avoid creating confusion within the DER marketplace. 

On October 19, 2018, the IOUs filed supplemental advice letters that would replace the original July 25 advice letters in its entirety. At the direction of CPUC Energy Division and the PAO, the IOUs proposed a template for reporting the date, number, type, and duration of grid frequency events. The reported data will be used to estimate the impact of activating Frequency-Watt mode on customers (Phase 3 Function 5) in terms of the count of instances where continuous system frequency events had the potential to reduce the output of smart inverters with activated Frequency-Watt mode. Specifically, SCE proposed to monitor frequency data from one of its frequency measurement devices located at one of its transmission substations, in conjunction with smart inverters that transmit frequency-watt reporting information. Quarterly reports will be provided starting in Q2 2019.

On October 25, 2017, a workshop was held to discuss and, if possible, resolve issues raised in the IOUs' advice letters to incorporate Phase 3 recommendations. The solar parties argued that there are a number of functions, such as volt-watt and scheduling capabilities, where the need has not been adequately demonstrated and compared against the potential impact to customers (e.g., NREL found that some customers could see up to 10% curtailment annually). They viewed these technical considerations as pre-empting policy discussions that are underway or are scheduled for consideration, and believe that these functions should be required capabilities at this time. 

On December 6, 2017, Draft Resolution E-4898 was issued on December 6, 2017 that modifies the Rule 21 tariff in response to some of the consensus developed at the workshop. The CPUC modified the IOUs’ proposed language regarding specific technical requirements, but mostly moved forward with the IOUs’ proposal, affirming that compensation mechanisms do not need to be developed in advance of the activation of Phase 3 functions and can still be developed in proceedings such as the IDER. The IOUs are thus directed to monitor the frequency and amount of curtailment posed by Functions 5 and 6 and to present findings to the CPUC two years after mandatory activation. The CPUC also clarified that Phase 3 development is intended to establish the capabilities of smart inverters, thereby clarifying that the above capabilities are mandatory but activation of these functions are optional.

In addition to the adopted modifications above, the Draft Resolution also approved the effective date of the requirement for smart inverters to perform Functions 1, 5, 6, and 8 to be the later of 11 months after the approval of these advice letters, or 9 months after the release of the SunSpec Alliance communication protocol certification test standard (or the release of another industry-recognized communication protocol certification test standard). For Functions 2, 3, 4, and 7, the effective date is determined to be the earlier of: December 2019 or 12 months after approval of the IEEE 1547.1 standard revision. These changes to the effective date better align with the next release of the IEEE 1547 and IEEE 1547.1 standards and to consolidate effective dates for Phase 2 and 3 functions into two dates. Before the effective date, the IOUs and the generating facilities are permitted to utilize any of these functions upon mutual agreement.

CESA supported most of the capabilities but opposed the mandatory activation of the frequency-watt mode (Function 5) without some form of compensation for these services. CESA noted how this mode would significantly impact energy storage systems because energy storage, unlike most customer-sited solar, can increase its output in response to a frequency dip. CESA also disagreed with the Draft Resolution categorizing primary frequency response, a system-wide service, as a service that can avoid or defer distribution upgrades. Meanwhile, the solar parties generally opposed the activation of Function 6 and Function 7 due to other existing standards in place to address issued intended to be resolved by these functions, to the lack of compensation for services provided by these functions, to potentially unintended effects harmful to customers, among other reasons. They also generally argued for the optionality of Function 8 and the collection of more data before mandatory activation of many of these functions. Instead, many parties argued for the mandatory capabilities of these functions.

See CESA's comments on December 29, 2017 on Draft Resolution E-4898

On April 26, 2018, Final Resolution E-4898 was issued that adopted the following schedule for implementation. 

On May 22, 2018, the SunSpec Alliance approved its CSIP Conformance Test Procedures, which meant that Phase 2 requirements and Phase 3 Functions 1, 5, 6, and 8 will become mandatory for generating facilities utilizing inverter-based technologies for interconnections requests submitted on or after February 22, 2019.

On May 25 and 29, 2018, the IOUs filed their supplemental advice letters requesting modification to Rule 21 to incorporate Phase 3 smart inverter advanced functions pursuant to Resolution E-4898. IREC and CALSSA, however, protested the advice letters for not aligning the Frequency-Watt settings with IEEE 1547 2018 defaults, instead using the settings currently in Section Hh.2.2, which have a slope (50% per Hz) that is not based on the default IEEE 1547 settings (33% per Hz); they point to this as requiring a more extreme reduction in power that that called for by IEEE 1547. IREC and CALSSA argued that the Set Active Power Level function is not fully described and recommended that it should denote that this is a control function, which would allow for control of, for example, an energy storage device to control its output level. IREC and CALSSA also commented that the ride-through exceptions for backup systems should remain in Rule 21. 

On June 4, 2018, a stakeholder call was held on June 4 to identify and agree on actions and steps to implement the reactive power priority setting. The SunSpec Alliance approved the CSIP Conformance Test Procedures that will now allow manufacturers, system integrators, and implementors to verify products for compliance to Rule 21 Phase 2 and 3 requirements. Availability of these test procedures started the nine-month clock on the Rule 21 Phase 2 mandate. This meant that secure communication from the IOU to the DER system will be required starting in early 2019.

During the same stakeholder call, stakeholders identified and agreed on actions and steps to implement the reactive power priority setting. Several inverter manufacturers (e.g., Enphase, Outback, Sunpower, SMA) indicated on the call that they have already been certified for the reactive power priority mode, but concerns were raised on the readiness of installers to ensure that this function is enabled. If not yet certified, including those with inverters for non-solar technologies, these inverter manufacturers will need to get certification from a Nationally Recognized Testing Laboratory (NRTL) and then apply to the CEC to be listed as a certified inverter manufacturer meeting this new requirement. The CEC indicated that it will standardize the certification file format. Stakeholders proposed ideas to harmonize smart inverter terminology with that of IEEE 1547 to reduce industry confusion as well as a potential “soft start option” to allow deemed compliance if inverters are UL-1741-SA certified for an interim period at the beginning of implementation on July 26, 2018.

On July 25, 2018, each of the IOUs filed advice letters on their frequency event reporting methodology. The IOUs discussed how they will count the instances where the smart inverter output would be impacted above established threshold levels. Frequency-Watt mode is a default inverter setting that decreases real power production when grid frequency rises above 60.036 Hz and increases real power production when frequency drops below 59.964 Hz, in accordance with IEEE 1547. ORA filed a protest to all the IOU advice letters, requesting that the IOUs monitor system frequency data at a specific location that is as close to the distribution system as possible and to provide frequency measurements in Hz to understand the frequency stability issue further. The IOUs responded that it makes no difference where on the system that frequency is monitored since the grid operates at a common synchronized frequency. The IOUs also pushed back against the quantity of frequency measurements in Hz due to the burdensome nature and because the IOUs already plan to record the data every four seconds.

On August 15, 2018, a meeting was held to discuss Volt-Var and Volt-Watt monitoring and reporting requirements and get feedback on the manufacturers’ plan for logging smart inverter function activation. With Volt-Watt reporting and voltage complaint process reporting beginning three months after mandatory activation of the Volt-Watt mode (February 22, 2019), the IOUs shared their proposal for monitoring and reporting when voltage complaints are received. The IOU AMI data will be utilized to determine which side of the meter is experiencing voltage issues and the smart inverter will log when the Volt-Var and Volt-Watt functions activate.  Even though the real power losses from the Volt-Var and Volt-Watt settings are expected to be de minimis due to the rarity of curtailment events, the CPUC directed the IOUs to report on their voltage complaint resolution process for both DER and non-DER customers.

On August 23, 2018, a call was held where the IOUs presented a more detailed proposal on voltage monitoring and reporting. The IOUs explained that each voltage curtailment case will be evaluated by requesting smart inverter data and compare it to against PVWATTS, which will be used assuming site-specific details to estimate the output based on irradiance during the curtailment periods. Specifically, the IOUs will review kVAR increase from previous readings versus kW decrease to assess Volt/Var and review kW decrease from previous readings versus irradiance changes to assess Volt/Watt. The IOUs noted that IEEE 2030.5 communications capabilities are required for these smart inverters to implement this reporting process (as reflected in the three options available in Rule 21 Section Hh).

On September 14, 2018, the IOUs submitted supplemental advice letters that clarified the effective date of February 22, 2019 for Phase 3 Functions 1, 5, 6, and 8 due to the approval of the SunSpec Alliance Communication Protocol Certification Test Standard, among other minor technical modifications. The IOUs each made minor technical changes to more granularly specify the system frequency thresholds and default deadbands for active power function and to modify requirements to communicate “percentage of operations of energy storage capacity” (instead of available kWh) for Volt-Watt requirements.

On January 3, 2019, the CPUC issued a letter that extended the deadline by six months from February 22, 2019 to August 22, 2019 to comply with Phase 2 communication requirements and with Phase 3 Functions 1 and 8. The CPUC agreed with the extension request from CALSSA, who justified the request based on the gaps in the certification regime (e.g., CSIP procedures do not provide for end-to-end testing). The CSIP was found to have significant gaps in testing and certification needs of industry and utilities, and the IOUs compounded the complex implementation problem with a late release of implementation plans.

On February 20, 2019, the IOUs submitted a supplemental advice letter that proposed a delay of the Phase 2 certification requirement date until 12 months after IEEE 1547.1 is approved since its certification testing will resolve the issues raised about end-to-end testing and utility requirements to conduct their own end-to-end testing and Phase 3 functional certification. Several vendors disagreed with the IOUs’ proposal because it would risk failure to achieve the state’s goals, reduce confidence in the Rule 21 compliance dates, and penalize vendors who have made good-faith investments to meet the August 22, 2019 deadline.

On February 22, 2019, all inverter-based generation was required to implement and activate Function 5 (Frequency-Watt Mode) and Function 6 (Volt-Watt Mode). The CEC provided an update on their “Grid Support Inverter List” that reported that only 60% of all CEC-listed inverters have certification approval for the effective date. The IOUs will continue to reach out to manufacturers for awareness of submittal of documentation to avoid any delays. Industry providers can submit the NRTL documentation for new requirements certification to the CEC at any time using the existing Inverter Listing Request Procedure.

On November 21, 2019, CALSSA requested a two-month extension of the deadline to comply with the Phase 2 communication requirements and with Phase 3 Functions 1, 2, 3, and 8 from January 22, 2020 to March 22, 2020. The CPUC granted the extension request because additional time will provide industry more opportunity to adapt to the smart inverter requirements while avoiding market disruption.

On December 23, 2019, Resolution E-5016 was issued that rejected the IOUs’ proposal for standardized reporting methodologies to monitor the frequency and amount of voltage excursions due to the lack of sufficient detail related to the quality of data and structure of the data reported. Instead, the IOUs are directed to re-file their advice letters to comply with Resolution E-4898.

On March 17, 2020, Fronius USA and Ginlong Solis USA requested a four-month extension of the deadline to comply with the Smart Inverter Phase 2 communication requirements and with Phase 3 Functions 1, 2, 3, and 8 due to travel restrictions put in place in response to the COVID-19 pandemic. The CPUC granted the extension from the current deadline (March 22, 2020) to June 22, 2020 and the IOUs submitted advice letters accordingly.


On May 21, 2020, each of the IOUs submitted an advice letter on a proposed methodology to collect and report on data that informs of the number and duration of voltage excursion events from inverter-based DERs. The IOUs elaborated on the specifics of the available modeling tools (e.g., NREL Hawaii method, NREL PVWatts, NREL Method 1 and 2), including the pros and cons of each methodology and an assessment of the technical feasibility of each, as well as the use of AMI voltage data. Based on collaboration with the SIWG, the IOUs proposed that their voltage complaint process will be the basis for voltage reporting to satisfy CPUC requirements, and that the IOUs will provide curtailment calculations for volt/watt-enabled customers in the voltage complaint process with voltage readings over 106% of nominal voltage with the following characteristics:

• Include calculations for all utility-caused, customer-reported issues per reporting period (consensus)

• Report on up to 20 of the first customer-caused and reported issues on an annual basis (consensus)

• When the event duration is less than 48 hours, it will be considered a limited anomaly and will not be reported (non-consensus)

The IOUs will use the NREL Method 1 process using currently available AMI data to calculate estimated curtailment utilizing the following processes for estimation calculation:

• Voltage intervals of 1-hour for residential or 15-minute for commercial as available

• Average voltage readings utilized over the voltage interval for SDG&E/SCE and instantaneous voltage readings for PG&E based on existing capabilities

• NREL Method 1 is only being approved for generalized/anonymous reporting but not for potential individual customer claims

• For 3-phase service points, the average voltage per phase will be used for curtailment estimation

• Any missing or removed data due to data quality will be removed from numerator and denominator of percentage of curtailment calculations

Under NREL Method 1, an 8760 voltage profile is obtained, and the approved volt/watt curve is utilized along with the simplified production profile to calculate the estimated PV curtailment.

Net Energy Metering Successor Tariff (R.20-08-020)

Background

On September 3, 2020, an Order Instituting Rulemaking (OIR) was issued to revisit the NEM 2.0 tariffs pursuant to D.16-01-044 and develop a successor tariff (NEM 3.0) that will still adhere to the principles and requirements of AB 327. In other words, similar to the NEM 2.0 tariff, NEM 3.0 development will balance costs and benefits of the renewable generation facility and allow customer-sited renewable generation to grow sustainable among different customer classes, which will be supported by an examination of the NEM 2.0 tariff. Other residual NEM issues will be addressed as well, including Virtual Net Metering (VNEM), NEM aggregation (NEMA), other NEM tariffs applicable to fuel cell customer-generators who use non-renewable fuel, and consumer protections. The Preliminary Scoping Memo proposes to adopt a successor to existing NEM tariffs no later than December 31, 2021.

CESA supported the broad scope of issues at this stage to identify guiding principles, program elements, and possible options for the NEM successor tariff.  While the scope of this proceeding is broad and general at this time, CESA recommended that the CPUC evaluate policies, procedures, and rules that enable oversizing of and/or excess export from energy storage paired with NEM-eligible generation while adhering to NEM integrity, and  consider concepts to enable storage that is not paired physically but paired contractually to be eligible for NEM credits.

See CESA’s comments on October 5, 2020 on the Order Instituting Rulemaking

The IOUs and CUE emphasized the need to maintain affordability and pointed to the NEM 2.0 Lookback Study that found an average RIM score of 0.46, highlighting the cost shift from participants to non-participants. The RIM test is preferred for use in this proceeding. NRDC joined the IOUs in advocating modifications to NEM to address the cost shifts and inequities, including for low-income NEM customers who are compensated at lower rates by virtue of being on CARE/FERA rates. Notably, the IOUs sought to include legacy NEM customers in the scope of this proceeding since they are the source of the most significant cost shifts and recommended that enrollment on NEM 2.0 close as quicky as possible to avoid a gold rush to interconnect on the more favorable NEM 2.0 tariff. However, SEIA, Vote Solar, and CALSSA emphasized the need to continue to grow customer-sited renewable distributed generation given their need as identified in the IRP Reference System Portfolio (i.e., 1 GW per year through 2030 with associated storage). In addition, the full scope of benefits must be accounted, including those not captured by the Avoided Cost Calculator (e.g., resiliency, reliability, grid services). GRID Alternatives agreed but added that this proceeding should have explicit principles or program elements considering low-income customers. TURN and PAO outlined principles and advocated for a Value of DER (VDER) tariff.

Net Energy Metering Successor Tariff (R.14-07-002)

Background

The Net Energy Metering (NEM) Tariff is applicable to customers who use a renewable electric generation facility with capacity not exceeding 1 MW, and is intended to offset part or all of the customer's electrical requirements with electricity provided directly by their renewable energy facilities. The rate schedule is available on a first-come, first-served basis. Projects participating in the NEM program are eligible to participate in the Self-Generation Incentive Program (SGIP).

NEM systems are eligible for financial credits for power generated by their onsite systems that is fed back into the power grid for use by other utility customers over the course of a billing cycle. The credits are valued at the same $/kWh that customers would otherwise be charged for electricity consumed. Net credits created in one billing period carry forward to offset customer generators' subsequent electricity bills, and at the end of the year, the credits and charges accrued over the previous 12-month billing period are trued up. A customer producing power in excess of its onsite load over the 12-month period may be eligible for "net surplus compensation" under certain conditions (i.e., usually equal to the wholesale generation rate). Netting can be allowed at different intervals ranging from instantaneous to annual - i.e., in California, meter readings are done in hourly intervals for residential customers and 15-minute intervals for commercial customers, while netting is done annually. 

AB 327 is a multi-part bill that affects a number of aspects of regulated utility service and of the energy market, including NEM. The CPUC opened a rulemaking proceeding to develop a NEM successor tariff that will address existing issues in the current NEM program as well as a NEM successor tariff to be finalized by December 31, 2015. The current NEM program expires at the earlier of: (1) July 1, 2017; or (2) NEM total rated generating capacity of 5% of the IOUs' aggregate peak demand. 

On July 10, 2014, the Order Instituting Rulemaking (OIR) was issued that started this proceeding to develop a successor tariff to the NEM program authorized in Section 2827. 

On March 4, 2017, the Second Amended Scoping Memo was issued that established the following as the scope of the remainder of the proceeding:

• Consideration and adoption of alternatives to encourage growth of distributed generation by residential customers in disadvantaged communities (DACs)

• Oversight and administration of the successor tariff adopted in D.16-01-044

• Implementation of AB 693 Program to provide monetary incentives for the installation of solar PV systems on multifamily affordable housing properties

• Consumer protection under the successor tariff

• Measurement, evaluation, marketing, and outreach for distributed generation programs

On August 31, 2017, the Third Amended Scoping Memo was issued that identified the remaining issues and adopted a procedural schedule for the remainder of this proceeding:

• Consideration and adoption of alternatives to encourage growth of distributed generation by residential customers in DACs

• Oversight and administration of the successor tariff (D.16-01-044)

• Implementation of AB 693 Program to provide monetary incentives for the installation of solar PV systems on multifamily affordable housing properties

• Consumer protection under the successor tariff

• Measurement, evaluation, marketing, and outreach for distributed generation programs

• Implementation of AB 1637 to implement an emissions performance standard for NEM fuel cell customers, once a standard is adopted by the State Air Resources Board

• Resolution of the PFM requesting the exemption of multifamily affordable housing (MASH) customers on Virtual Net Energy Metering (VNEM) tariffs from taking service on a TOU rate

• Consideration of possible tariff modifications to facilitate the use of energy storage systems by customers taking service under VNEM tariff provisions

NEM alternatives for DACs and AB 693 implementation were highlighted as the priorities for this proceeding. In spring 2018, the CPUC plans to close this proceeding and adopt a new OIR on NEM issues focused on the evaluation of existing NEM tariffs and programs and the development and adoption of successor tariffs (i.e., NEM 3.0).

On March 29, 2018, a Fourth Amended Scoping Memo was issued on March 29 that recapped how this proceeding has addressed a number of issues, including:

• Establishing an implementation framework for AB 693 by creating the Solar on Multifamily Affordable Housing (SOMAH) Program

• Facilitating adoption of paired energy storage by customers taking service on a VNEM tariff

• Modifying the bill credit estimation methodology for NEM-eligible facilities paired with small storage devices

• Adopting proposals for alternatives to promote distributed generation in DACs

It also highlighted several issues that are still outstanding, including the oversight and implementation of the SOMAH Program and measurement and evaluation of the NEM tariff and how the NEM tariff is facilitating growth of distributed generation in DACs.

• Consumer protection under the successor tariff and any alternatives for DACs that may be adopted

• Implementation of AB 1637 set an emissions performance standard for NEM fuel cell customers, once a standard is adopted by the ARB

• Resolution of the PFM requesting the exemption of MASH customers on VNEM tariffs from the otherwise applicable requirement that NEM customers take service on a TOU rate

• Resolution of the PFM requesting modifications to allow DC-coupled systems for large NEM-eligible facilities paired with energy storage

• Resolution of the PFM requesting modifications to the definition of “small” NEM-paired energy storage from less than or equal to 10 kW, to less than or equal to 30 kW

On December 21, 2018, the Fifth Amended Scoping Memo was issued that identified consumer protection issues and resolution of outstanding PFMs as the priority for this proceeding.

On June 28, 2019, the Sixth Amended Scoping Memo was issued that identified consumer protection issues and resolution of outstanding PFMs as the priority for this proceeding, similar to the previous Scoping Memo, but the anticipated schedule for a new OIR to revise the NEM tariff is expected to be issued by Q1 2020 – yet another delay from the previously estimated OIR start date of Q2 or Q3 2019. In this new OIR, the CPUC will begin evaluation of the existing NEM 2.0 tariff and consider development of a successor tariff, which may incorporate locational granularity.

On August 15, 2019, a prehearing conference was held to identify parties and discuss procedural issues such as the need for evidentiary hearings or workshops, and the proceeding scope and schedule. Most issues have been addressed but the ALJ highlighted how the CPUC must still resolve how eligible fuel cell customer generators can achieve the NEM standards and requirements, once the Air Resources Board (ARB) adopts the CPUC’s performance standard for NEM fuel cell metering. Other outstanding issues include the measurement, evaluation, ME&O, and administration of the NEM Successor Tariff. Once addressed, this proceeding will close, with a new rulemaking expected mid-2020 to evaluate the NEM Successor Tariff. Meanwhile, a review of the IOUs’ NEM 2.0 tariffs will kickoff soon, as SDG&E issued an RFP on behalf of the CPUC to conduct this $1.5-million evaluation.

Net Energy Metering for Fuel Cells (NEMFC)
On June 12, 2018, PG&E filed an advice letter that would modify the NEMFC tariff to allow a NEM generating facility to include an energy storage device using a non-import relay equivalent, modeled after a similar generator and storage arrangement for VNEM tariffs. This tariff amendment came from Bloom Energy’s request to PG&E to seek a way to incorporate energy storage with fuel cell generation while maintaining NEMFC eligibility.

On July 2, 2018, Sierra Club, ORA, and TURN protested the advice letter because the tariff amendment did not contain any requirement to limit their applicability to fuel cells that use renewable fuel. TURN took a stronger stance that there does not seem to be an inherent basis for integrating energy storage systems with fuel cells that are already dispatchable, unlike variable renewable generators. Sierra Club questioned the eligibility of fuel cells under the NEM program altogether due to GHG emission concerns. ORA also recommended that a process to monitor and verify that fuel cells are only being powered by renewable fuels. 

On July 10, 2018, PG&E responded to these parties clarifying that the non-import relay equivalent for fuel cell installations simply describe the steps a fuel cell manufacturer would be required to undertake to establish that the energy storage unit could only charge from the paired fuel cell, not the grid. Importantly, PG&E added that fuel cells under NEMFC are not required to be renewably fueled. In addition, PG&E clarified that exports to the grid by fuel cells under NEMFC are credited at the generation component of the energy charge, not the full retail rate. As PG&E’s response revealed, NEMFC operates differently from the regular NEM tariff in many ways, where renewable generation is absolutely required for the latter and not the former.

Net Energy Metering Aggregation (NEMA)

In NEMA configurations, a solar PV system serves multiple meters on properties that belong to the same customer and are contiguous to property where PVs are located. 

Renewable Energy Self-Service Bill Credit Transfer (RES-BCT) Program

On January 1, 2009, the Legislature established the RES-BCT Program and codified through AB 512. This program allows governmental entities, who may not have electric loads where the potential for renewable generation exists, to nevertheless install renewable energy generation projects in those locations. The program allows local governments to generate energy from an eligible renewable generating facility, up to 5 MW per generation account, for its own use and to export energy not consumed by the generating account to the electric grid. Any energy exported by the renewable generating facility to the grid is calculated into bill credits and applied monthly to the designated benefiting accounts. The value of the credit for the exports to the grid from the renewable generator is established using only the generation component of the TOU energy charge of the generator account rate schedule. This differs from the NEM tariff, which provides project owners a credit equal to the entire retail rate. Thus, RES-BCT generation credits are heavily dependent on the peak hour pricing structure of SCE's TOU periods. 

NEM Consumer Protections

Background

On July 10, 2018, the CPUC organized a public forum in Huron, CA to provide an opportunity for local community members to share concerns, learn about current consumer protections, and identify ways to improve protections. Forum attendees identified the following areas of concern:

• Unfair lending practices for solar purchases

• Misleading or false sales representations

• Aggressive sales tactics and contract enforcement

• Complexity of sales proposals and contracts

• Damage from and performance problems with solar installs

• Lack of response from vendors and regulatory institutions

• Lack of timely consumer protection oversight

To address these concerns, forum attendees discussed possible solutions including legal action, recourse through the California State License Board (CSLB), assistance from SEIA, and even moratoriums on solar installs. Some prospective solutions included a more transparent and fairer sales process, leveraging the utility-to-consumer relationship, and providing educational materials. 

On September 4, 2020, the CPUC published the California Solar Consumer Protection Guide. 

California Solar Consumer Protection Guide

On August 24, 2018, Resolution M-4836 was issued that supported the CPUC’s collaboration with the CSLB to draft the solar consumer disclosure document.

On August 24, 2018, a PD was issued that proposed to adopt several consumer protections targeted to solar customers. In comments, the IOUs and solar parties differed on whether a NEM evaluation plan was appropriate and needed, while the IOUs recommended that interconnection fees be increased for NEM systems to recover the costs of implementing the consumer protection measures.

On October 5, 2018, D.18-09-044 was issued that adopted several consumer protections targeted to solar customers, including the development of a new consumer information packet primarily geared to residential consumers of rooftop solar to educate them on installation and NEM tariff provisions and to mitigate risks of predatory sales tactics. The IOUs were also directed to ensure that solar customers have received and read both the information packet and the CSLB Solar Energy Systems Disclosures Document prior to interconnecting their systems and to collect and review installation contracts for reasonableness, which the decision envisions can be done through interconnection portals. Finally, the decision directed a NEM successor tariff evaluation to be conducted for public review and comments, including a draft research plan and public workshop/webinar. The decision was not changed from the PD.

On November 5, 2018, SEIA filed an application for rehearing of D.18-09-044 that focused on one element of the decision around eliminating the requirement of a wet signature on the signature page of the information.

On February 27, 2019, a workshop was held on the draft solar information packet, where stakeholders provided input on the sequencing, structure, and effectiveness of the content, which is intended to ensure customers read the packet and provide their signatures as a consumer protection measure.

On March 8, 2019, a Ruling was issued soliciting comment on enhanced consumer protection measures for customers (potentially) taking service on a NEM tariff. The Ruling considered a number of potential measures, such as establishing an administrative penalty mechanism for infractions, establishing an independent consumer advocate or consumer clearinghouse, and developing and maintaining a list of “approved” solar providers. Alternatively, a list of “non-approved” solar providers enforced via the interconnection process was proposed. For each, a consideration of the likely benefit-cost ratio is needed. The CPUC is also contemplating establishing a restitution fund for customers that have been financially harmed by solar providers’ unfair business and financing practices.

The low-income and ratepayer advocates largely supported the CPUC staff proposal. Notably, GRID Alternatives proposed the use of Program Administrators (PAs) of incentive programs (e.g., by withholding or suspending ‘bad-actor’ contractors) to enforce consumer protections. The IOUs were generally supportive as well but commented that the prohibition against interconnection would be ineffective and recommended that the CPUC clarify and/or identify the CSLB as having jurisdiction over implementing and enforcing consumer protection through the “approved” contractor list. Rather than duplicating efforts, the IOUs recommended that the CPUC focus on providing information and maintaining lists and the IOUs focus on protecting customer information. In addition, the IOUs opposed the restitution fund unless it was recovered from solar providers only and/or through fees in DER-related incentive programs. Meanwhile, the solar parties pushed back against many of the CPUC staff’s proposed measures, which are in reaction to a few bad actors and are not founded on more comprehensive public data of customer complaints. Instead, they identified various laws and codes of conduct already in place for customer acquisition, licensing, and contracts, where a ‘blacklist’ or another set of enforcement measures would create confusion.

On August 19, 2019, D.19-08-039 was issued that disposed of the Application for Rehearing of D.18-09-044 filed by SEIA. The decision found that D.18-09-044 did not violate the Uniform Electronic Transactions Act by requiring wet signatures on the solar information packet signature pages and how the wet signature requirement is a proper exercise of the CPUC’s authority under Section 701.

On September 30, 2019, the IOUs reconfigured their interconnection portals to require solar providers to upload signed pages of the Solar Information Packet (called the California Solar Consumer Protection Guide), with either a wet or an electronic signature. Only wet signatures will be allowed starting on January 28, 2020. 

On October 18, 2019, a Ruling was issued that continued the CPUC’s efforts to enhance consumer protections for customers adopting NEM solar systems due to ongoing concerns of “unscrupulous vendors” who mislead or defraud customers. A decision (D.18-09-044) was previously adopted, but this Ruling aims to enhance these measures by seeking stakeholder feedback on two proposals: (1) allow solar providers to obtain electronic signatures on the solar information packet instead of handwritten on a hard copy or “wet” signatures; and (2) require solar provider registration to be potentially enforced by an accompanying citation program.  On the latter, these include the potential creation of a consumer advocate or centralized clearinghouse, establishing a list of approved or blacklisted solar developers/providers, establishment of administrative penalties, creation of a restitution fund, and measures for registration or regulation similar to those applicable to Core Transport Agents.

Other than the solar parties, everyone was generally supportive of the Staff Proposal. While SCE indicated that it would integrate the attestation process into its interconnection portal process, PG&E recommended that the attestation process be completed prior to entering the interconnection process since many solar projects are installed prior to pursuing interconnection. GRID Alternatives did not oppose many measures but tried to find middle ground by advocating for either electronic or wet signatures since two-step authentication can be burdensome, and certain proposals, such as the Solar Transaction Record (STR), can be redundant for programs already overseen by the CPUC. Meanwhile, CALSSA and SEIA strongly opposed the annual solar developer registration process and citation program as being outside of CPUC jurisdiction (i.e., solar providers are not public utilities) and because it would deny qualifying facility (QF) rights and would be duplicative of Contractors State Licensing Board (CSLB) and Department of Business Oversight (DBO) role in enforcing contractor law.

On February 14, 2020, D.20-02-011 was issued and revised to make certain clarifications and to remove references to the CPUC’s authority for additional consumer protections but was otherwise unchanged from the PD. In issuing this decision, the CPUC sought to refine the consumer protection rules, including its enforcement, sought to ensure that defrauded solar customers are entitled to relief. The decision adopted additional consumer protection measures, including attestations, audit trails, and additional interconnection data collection:

• Requires applicants to submit valid third-party PACE program administrator licenses, if applicable, at interconnection

• Requires each IOU in its interconnection portal to include the ability to upload signed attestation pages, to add a new field for the entry of the name of the financial institution associated with the financing of the solar project, and to collect and transmit interconnection information to the CPUC, CSLB, and DBO (instead of a solar provider registration process)

• Grants customers the option to meet the consumer protection requirement that a solar provider obtain a customer’s signature on the solar information packet may be met through either a “wet” signature or an electronic signature, in line with SEIA’s Petition for Modification (PFM)

• Directs the Consumer Protection and Enforcement Division to propose a citation program for the consumer protection requirements created by D.18-09-044

• Previews that the CPUC will issue a future Ruling on the development of a restitution fund for solar customers who have been defrauded by going solar

In comments to the PD, SCE recommended that documentation of attestations to completing consumer protection measures be completed as well in the interconnection process to simplify the process and reduce paperwork. SEIA limited its comments on the lack of CPUC jurisdiction to develop a citation program or restitution fund. PG&E and SDG&E expressed some concerns with the implementability of such significant changes in their view, especially in light of their recent IT system upgrades. The decision was not materially changed in response to these comments from parties.

On April 27, 2020, Draft Resolution UEB-004 was issued by the Consumer Protection & Enforcement Division (CPED), established through D.20-02-011, that adopted a citation program to ensure compliance with NEM solar consumer protections. Non-compliance is defined as “an installation application submitted to the IOU interconnection portal that has failed to comply with the consumer protection requirements due to the applicants’ failure to upload the required attestations, verifications, or certifications. The IOUs could be penalized for allowing solar providers to interconnect after being flagged for incomplete or inaccurate consumer protection attestations. The solar groups (SEIA, CALSSA) submitted comments that expressed that the provisions would impose substantial and unfair burdens on solar contractors rather than partnering more deeply with the CSLB, and would exceed the parameters established in the authorizing decision. California Low-Income Consumer Coalition (CLICC), on the other hand, supported the proposed enforcement mechanisms.

On May 18, 2020, the IOUs submitted a PFM of D.20-02-011 because the decision shifted the target of the citation program to the IOUs, instead of the solar providers. As a result, they requested that the IOU citation program be eliminated or deferred in order to explore other options, such as a registration program, a secure portal for regulator access to documentation and information collected at interconnection, increased frequency of spot audits, among other ideas.

PG&E and SCE reconfigured their interconnection portals to incorporate the Solar Consumer Protection Guide on September 30, 2020, with SDG&E implementing these requirements by January 4, 2021.

NEM Alternatives for Disadvantaged Communities

Background

On March 14, 2017, a Ruling was issued that seeks updated proposals and/or comments on alternatives for disadvantaged communities. Several parties, including SCE, PG&E, CalSEIA, and the MASH Coalition, have been advocating for maintaining the MASH program structure and administration in its implementation of Assembly Bill 693 given the simplicity/success of the MASH program. They also agreed that AB 693 should not fund energy storage technologies since there is no technical manner to benefit tenants with virtual net metering and energy storage and because few multifamily properties are on tariffs with demand charges. 

On April 24, 2017, a few proposal updates were submitted. The Joint Solar Parties introduced their DAC VNM Proposal that proposed to expand the VNEM tariff to allow both bundled and unbundled customers in DACs to subscribe and be assigned VNEM credits, so long as the project and participating customers are located in any designated DAC within the same IOU service territory. The DAC VNM project owner would submit an electronic form every six months to the utility outlining the customer accounts that have subscribed to a share of the generation from the solar project and thus assign VNEM credits in accordance. This proposal thus aimed to not require subscribing customers to not be co-located with projects. TURN, meanwhile, submitted a proposal to modify the Environmental Justice component of the Green Tariff Shared Renewables (GTSR) Program to pay any net costs associated with subscriptions by participating low-income customers living in DACs to the utilities GTSR Program. TURN also proposed to expand the Single-Family Affordable Solar Homes 2.0 program eligibility to include single-family housing units in DACs.

Green Tariff & Community Solar Program Adoption

On February 20, 2018, a PD was issued on February 20 that adopts two new programs to promote the installation of renewable generation among residential customers in DACs, pursuant to AB 327. Specifically, the PD approves a new DAC Single-Family Solar Homes (DAC-SASH) Program to provide assistance for low-income customers in overcoming barriers to the installation of solar energy by providing upfront financial incentives, while the DAC-Green Tariff (DAC-GT) Program is modeled after the Green Tariff Shared Renewables (GTSR) Program to provide a 20% rate discount to their applicable tariff (given that GTSR is a premium-price product due to the inability to shift costs to non-participating customers). The participation caps for the DAC-GT Program will be 70 MW for PG&E, 70 MW for SCE, and 18 MW for SDG&E, and projects must be located in the top 25% of communities statewide based on the CalEnviroScreen 3.0. The DAC-SASH Program will be run by a single statewide PA. Both of the proposed new programs will be funded by GHG allowance proceeds, are intended to provided “additional tools” to supplement the recently approved SOMAH Program, and are aimed to provide special focus to low-income customers and DACs.

However, an Alternate PD by Commissioner Guzman-Aceves was also issued that proposed adopting the same two programs, as in the PD, but also to adopt an additional, new Community Solar Program to allow low-income and disadvantaged customers to benefit from the development of solar generation projects located in their own or nearby communities. These customers may not have suitable roofs or may rent rather than own their homes, thus making a program similar to the current VNEM programs a viable option. Eligible projects are based on being located within the top 5% of the CalEnviroScreen 3.0 or within 5 miles of communities scoring in the top 5% of the CalEnviroScreen 3.0 but still located in a top 25% of the CalEnviroScreen 3.0. Low-income households within these communities are specifically targeted. The total program capacity for PG&E, SCE, and SDG&E will be 18 MW, 18 MW, and 5 MW, respectively, and CCA and ESP customers will be eligible if all the other eligibility criteria are met. Other specifics to this Community Solar Program include:

• Requiring at least 50% of the community solar project’s capacity to be allocated to low-income customers

• Limiting certain non-residential customers to 25% of a project’s capacity

• Limiting the host to 50% of the project’s capacity

• Limiting any given project to 30% of an IOU’s total program capacity

• Exempting CARE and FERA eligible customers from mandatory TOU rates

The Alternate PD also made clear that the statutory requirement to ensure that the total costs are approximately equivalent to total benefits should not be applied in the development of alternatives for DACs, considering the multiple policy goals, including to create an equity program and to ensure continued growth in this particular customer segment. Given the different needs of different groups, the Alternate PD also favored offering multiple program options for low-income residents in DACs. 

On March 12, 2018, multiple parties filed comments. The solar parties and environmental advocates supported the Alternate PD since they supported the DAC-SASH and DAC-GT Programs and view the Community Solar Program, with modifications, as addressing gaps in the other two proposed programs. The CCAs are in support of all proposed programs but with modifications to the decisions to ensure that they can offer their own similar programs. CALSSA, SEIA, and GRID Alternatives, while supporting the intent of the Alternate PD, believe that the restrictions on the size and type of community will limit the success of the Community Solar Program and thus offered some modifications. Meanwhile, the PG&E and SDG&E favor the PD because they did not find the Community Solar Program in the Alternate PD to not effectively target low-income customers, lack sufficient consumer protections, and lack transparency or guardrails against cost-shifting, unlike budgeted programs. TURN also expressed cost-shifting concerns of the Community Solar Program and recommended revisiting this proposal, unless it is re-scoped as a pilot, when the NEM Successor Tariff is revised in 2019. Interestingly, even though SCE favored the APD, it recommended modifications but also proposed to submit an alternative Community Solar Program proposal without using VNEM within the same timeframe proposed by the APD to be “larger, scalable, and more cost-effective” to its customers.

On May 22, 2018, a Revised Alternate PD was issued by Commissioner Guzman-Aceves that proposed to adopt the same two programs above but also proposed to adopt an additional new program, the Community Solar Green Tariff Program, to allow low-income and disadvantaged customers to benefit from the development of solar generation projects located in their own or nearby communities. Compared to the original Alternate PD, the Revised Alternate PD moved away from the VNEM-based model and instead decided to develop a community solar program based on the GTSR model. The difference between the DAC-GT Program and the Community Solar Green Tariff (CS-GT) Program is that the latter requires community involvement with the solar project through a local sponsor and will result in a solar facility serving a nearby community. In sum, the Revised Alternate PD addressed some of the cost-shifting concerns tied to a VNEM-based model, as raised by the IOUs, TURN, and ORA in comments, with a simpler Green Tariff-based model. Additionally, the Revised Alternate PD loosened the locational requirements to some degree, but given the intent of Commissioner Guzman-Aceves to ensure community ownership of projects and local benefits, the locational requirements were still tied to a 5-mile radius of the project site.

On June 11, 2018, comments were filed by parties. Universally, commenters requested clarification on whether the 20% discount for participants will be applied before or after the Green Tariff premium, with solar and low-income parties arguing that applying it before would drastically reduce economic savings. In general, parties also fell into two camps in response to the revised proposal:

1. Support for moving away from the VNEM-based model (IOUs, TURN, ORA) that resolve cost shifting concerns and allows for more stringent or higher low-income customer participation (due to reduced financing risk)
   
   

2. Livable support for the CS-GT program but preference for or need to develop VNEM-based models at later time (environmental justice, low-income and solar parties) to achieve statutory requirements, create direct ownership of projects by participants, and extend predictable NEM benefits to low-income customers
   
   

It appears that there is a common denominator of livable support for the Revised Alternate PD proposal for the CS-GT program, but parties proposed modifications to improve program viability, including adding further flexibility to locational or project sponsor requirements, providing mandatory TOU exemption or opt-out for participants, increasing or lowering low-income participation requirement, ensuring competitive neutrality and procurement offsets between IOUs and CCAs, removing cost cap for procurement given program’s locational and subscription constraints, and taking into account tiered rate structures in calculating discounts. Only SDG&E was strongly opposed to the CS-GT program, arguing that the discounts exceeded the legislative discount cap for CARE customers and that the CPUC is prematurely adopting a new program prior to review of the similar Enhanced Community Renewables (ECR) program.

On June 22, 2018, D.18-06-027 was issued that approved the Revised Alternate PD by Commissioner Guzman-Aceves. As a result, the decision approved a new DAC-SASH Program to provide assistance for low-income customers in overcoming barriers to the installation of solar energy by providing upfront financial incentives. The decision also approved a new DAC-GT Program modeled after the GTSR Program to provide a 20% rate discount to their applicable tariff (given that GTSR is a premium-price product due to the inability to shift costs to non-participating customers). The participation caps for the DAC-GT Program will be 70 MW for PG&E, 70 MW for SCE, and 18 MW for SDG&E, and projects must be located in the top 25% of communities statewide based on the CalEnviroScreen 3.0. The DAC-SASH Program will be run by a single statewide PA. Both new programs will be funded by GHG allowance proceeds (and then by public purpose funds if additional funding is needed), are intended to provided “additional tools” to supplement the recently approved SOMAH Program, and are aimed to provide special focus to low-income customers and DACs.

D.18-06-027 also approved an additional new program, the Community Solar Green Tariff (CS-GT) Program, to allow low-income and disadvantaged customers to benefit from the development of solar generation projects located in their own or nearby communities. This program will require community involvement with the solar project through a local sponsor and will result in a solar facility serving a nearby community. The new CS-GT Program will have the following design elements:

• Projects must be sited in the top 25% of census tracts per CalEnviroScreen 3.0 will be eligible but with a priority to the top 5% of census tracts

• Subscribers to the project must be residential customers located within 5 miles of the project and within a top 25% DAC (though not necessarily the same DAC)

• Program caps is set at 18 MW for PG&E, 18 MW for SCE, and 5 MW for SDG&E

• Program subscriptions from low-income customers must be at least 50% of project capacity (at least 25% to receive permission to operate)

• The maximum size of any one project is set at 30% of the total capacity of an IOU’s program or 3 MW, whichever is larger

• The bill credit is set at 20% of the otherwise applicable tariff instead of the energy portion of the bill (consistent with the DAC-Green Tariff Program)

• No local project ownership requirement is set, but developers must provide a letter of commitment from local sponsors, who are eligible to receive bill credits equivalent up to 25% of the project’s capacity (but not to exceed the sponsor’s energy needs)

• At least two RFOs for these programs must occur each year for each IOU for power purchase agreements (PPAs) for projects in conjunction but not in the same solicitation with the DAC-GT Program

• RFO auction price cap is set at 200% of the historical Renewable Auction Mechanism (RAM) clearing price

There were no major modifications in the adopted decision from the Revised Alternate PD, except the following:

• The decision clarified that the 20% bill credit (as well as any CARE/FERA discounts) should be applied to the “applicable tariff” (i.e., the Community Solar Green Tariff in this case), not the customer’s bill before signing up to the CS-GT Program. This was an area of confusion raised by many parties. Solar and low-income parties argued that applying it after would drastically reduce economic savings, but the decision likely declined to take this approach to be consistent with other discount structures based on the “otherwise applicable tariff” approach.

• The decision clarified that it will not institute an enforcement mechanism for the 50% low-income customer enrollment requirement, but that the IOUs must inform the CPUC if low-income enrollment drops below 35%.

• The decision determined that above-market costs of any unsubscribed energy from the program (i.e., customer subscription is less than output) be financed with GHG allowance proceeds and/or public purpose program funds.

• The decision clarified that, since all customers will be paying for these programs, CCA versions of these programs can also be created and be implemented via an advice letter process.

There were no community storage or paired storage elements in the decision, as it declined to adopt SCE’s suggested pilot on paired solar and energy storage systems. Instead, the decision pointed to the rules allowing the pairing of energy storage systems to VNEM installations through D.17-12-005. However, given SCE’s comments, there may be an opportunity to consider how energy storage could fit in within SCE’s idea development.

On July 23, 2018, SDG&E submitted an Application for Rehearing (AFR) on D.18-06-027 on the grounds that the 20% discount violates AB 327 for adopting an additional discount on top of already discounted CARE rates, that the 20% discount does not address the cost-shift implications, and that the Decision ignores the realities that SDG&E cannot meet the adopted schedule of implementation due to its implementation of its Customer Information System replacement project. 

On August 20, 2018, the IOUs filed advice letters implementing a new DAC-GT Program and new CS-GT Program, in accordance with D.18-06-027. The advice letters covered customer eligibility and enrollment terms, rate and discount design, procurement, cost recovery, participation of CCAs, ME&O, reporting, and program measurement and evaluation. Pending any protests, these advice letters will become effective on September 19, with RFOs to launch at least six months after approval of these advice letters. These programs are part of the CPUC’s efforts to support low-income customers and DACs to benefit from the development of solar generation projects. The CCAs protested the advice letters to delay implementation of the DAC-GT and CS-GT Programs until after stakeholder workshops to discuss implementation of CCA version of these programs and how CCA versions will interact with IOU-offered programs.

On October 17, 2018, D.18-10-007 was issued that clarified D.18-06-027 around how GTSR tariffs, a “premium” service, should not be considered the “otherwise applicable tariff” by which the 20% bill discount for residential customers participating in DAC-GT and CS-GT Programs would be applied. Whereas for low-incomed customers, the “otherwise applicable tariff” could be a CARE or FERA tariff. The PD also clarified that “Permission to Operate” for the CS-GT Program would allow for interconnection but withhold “Initial Energy Delivery Date” until the 25% low-income subscriber minimum is met, thereby balancing the need to not impede the project development process.

On June 3, 2019, Resolution E-4999 was issued to approve modifications to the DAC-GT and CS-GT Programs. Specifically, the Resolution proposed the following changes:

• Master-metered residential customers will be eligible to enroll in CS-GT programs as long as eligibility criteria around location and single customer cap space are met, similar to any other low-income residential customers.

• Customers are not required to enroll in, but must be only eligible to enroll in, CARE/FERA rates to participate in DAC-GT and CS-GT programs as income-qualified customers.

• Existing DAC-GT and CS-GT customers who have moved to a new residence will maintain their eligibility for these programs and do not have to be put on a waitlist if program capacity at the new location is still available.

• Non-residential community sponsors will only be eligible for a 20% discount on the portion of project generation to which they are subscribed after the CS-GT project has satisfied the 50% low-income requirement.

• Multiple community sponsors may participate in any single CS-GT project to receive the 20% bill credit, given their cumulative subscription is not more than 25% of the project’s generation.

• Community sponsors are no longer required to build awareness, screen customer eligibility, and assist customers with enrollment.

• Single customers have capacity limits of 2 MW of nameplate generation capacity in both the CS-GT and DAC-GT tariffs.

• A consistent definition of qualifying census tracts was established, including the additional eligible tracts that do not have a CalEnviroScreen score, that determined eligibility by census tract, not customer address, for the 5-mile radius requirement.

• Qualifying customers can be located within 40 miles of a CS-GT project for SJV pilot communities.

• NEM customers are not eligible to participate in the DAC-GT Program.

• Quarterly and semi-annual reports on resource procurement and customer enrollment are required.

• Clarifications to the RFO process are directed, including the consideration of both full capacity deliverability and energy-only projects.

Importantly, the Resolution reserved capacity for CCAs under both programs in proportion to the share of residential customers in DACs each CCA serves, although each CCA may elect to only develop one, rather than both, programs. CCAs that serve customers that are served by the same IOU may share and/or trade program capacity. For DAC-GT, two or more CCAs may elect to pool some or all of their capacity allocations to offer a shared RFO for projects to serve their DAC customers as CCA DAC-GT projects may be located in any DAC within the relevant IOU’s service territory. Similarly, two or more CCAs may elect to pool some or all of their capacity allocations for the CS-GT program, so long as the CS-GT projects procured meet the locational eligibility requirements such that the projects can serve eligible customers from all participating CCAs.

On August 2, 2019, the IOUs submitted advice letters that updated their DAC-GT and CS-GT Program budgets, provided their ME&O plans, and attached their RFO solicitation materials. Standard contracts for these programs will be based on the RPS technology-neutral pro forma contracts. For the CS-GT Program, only IFOM solar resources with a nameplate capacity of 4.39 MW or less qualify. BTM projects and energy storage resources are not eligible. 

On September 16, 2019, Resolution E-5020 was issued pursuant to D.18-06-027 that approved the DAC-SASH Program with a 2019-2030 total program budget of $120 million at $10 million per year, which will provide incentives for low-income customers to install solar energy. GRID Alternatives, the statewide program administrator (PA) is authorized to seek approval to work with a third-party ownership partner (Sunrun) under both the SASH and DAC-SASH programs. The Resolution also clarified that money allocated to specific projects by the end of 2030 can be used to fund incentive payments for those specified DAC-SASH installations by September 30, 2031. Finally, the Resolution approved GRID’s program implementation plan that includes the following elements:

• Application procedures

• Requirements for documentation of building and project eligibility

• Program budget that includes line items for incentives and administrative activities, including but not limited to marketing, education, and outreach;

• Specific job training requirements

• Data collection and reporting requirements

On September 16, 2019, a workshop was held to address CCA questions about implementing the DAC-GT and CS-GT Programs, including what happens to capacity allocations if a CCA expands, decreases, or launches. In response, the CCAs proposed that, every other year (beginning with review of programs on January 1, 2021), remaining capacity under the programs is assessed and capacity allocations are updated based on updated customer numbers using the remaining capacity as the program cap. The CCAs also discussed scenarios where a customer in an IOU program moves to CCA service, including around billing responsibility and discount tracking. For the IOUs, their DAC-GT and CS-GT Program RFOs will launch in late 2019, with two RFOs expected in 2020.

On November 25, 2019, GRID Alternatives submitted an advice letter providing notice that Sunrun will be the primary third-party ownership (TPO) partner for the SASH and DAC-SASH Programs, which included modifications to the term length of the Sunrun BrightSave Prepaid Agreement used in both programs from 20 years to 25 years as well as other modifications to comply with minimum consumer protection standards (e.g., warranties, liability and indemnification clauses, dispute resolution clauses, readability).

On January 28, 2020, a Ruling was issued seeking comment on how eligible customers should be enrolled. As a proposal, the CPUC recommended that PG&E automatically enroll customers from a targeted population, amounting to around 18,500 customers out of close to 283,000 total eligible customers in PG&E territory. The target population would be in the top 15% of CalEnviroScreen and those who meet the various criteria for high risk of disconnection. After such priority customers, the Ruling recommended that the remaining available program capacity could be served by all other eligible waitlisted customers. In response, the CCAs and GRID Alternatives were enthusiastically supportive. SDG&E, however, commented on the concerns of implementing a proposal without due process or discussion and for applying it to a single utility in the middle of implementation.

On April 24, 2020, GRID Alternatives submitted a PFM of D.18-06-027 highlighting several failures of the program in supporting low-income customers, DACs, and resiliency in line with SGIP priorities and the CPUC’s Environmental & Social Justice Action Plan, and thus requested the following:

• Double the DAC-SASH budget to $20 million per year starting in 2020: GRID argued that these funds are needed to target growing number of high-need customers, especially in light of the current economic situation. There are also sufficient GHG auction revenues to support this increased budget

• Include low-income census tracts and Tribal Lands: GRID argued that tribal lands are often overlooked because they are excluded from the DAC definition and thus are unable to take advantage of the program. In addition, with the wider eligibility, the program will better support emissions-free resiliency in HFTDs by including 146 new census tracts with more than 50% overlap with Tier 2 or Tier 3 HFTD.

• Adopt the 80% area median income (AMI) eligibility threshold: GRID argued that the current eligibility threshold of 250% of the Federal Poverty Level (FPL) disproportionately excludes low-income families living in high cost-of-living areas of the state.

In response, there was comprehensive support for the PFM from CALSSA and CCAs. The IOUs and PAO joined in support of some eligibility criteria, especially in including tribal lands. PAO supported expanding the criteria to include low-income census tracts in order to support those with the greatest need, but by the same logic, opposed the change to reflect AMI thresholds. SCE expressed willingness to change the criterion to reflect AMI, but all of the IOUs opposed the locational criteria to ensure customers are located in DACs, pointing to how the DAC-SASH Program is different from the SASH Program for this very reason. Both the IOUs and PAO opposed the increased funding request due to the lack of participation data and the need for an evaluation before adjusting the budget. Finally, the IOUs raised conflict-of-interest concerns of the PA requesting a budget increase. Overall, CESA viewed the PFM as better supporting alignment of the low-income solar incentive program with the SGIP Equity Resiliency Budget, making more customers eligible to be supported by incentives for solar that would be paired with SGIP-funded storage in order to provide resiliency. Some of the eligibility changes represented reasonable quick fixes.

On May 18, 2020, Energy Division issued a non-standard disposition letter that approved PG&E’s fourth supplemental advice letter that adequately addressed the Joint CCAs’ requests to clarify: (a) the ability of CCA customers to participate in their respective CCA’s DAC-GT or CSGT programs; (b) the percent of CSGT participants’ total load that will be provided with renewable energy; and (c) the identification of new DACs through updates to the CalEnviroScreen. In addition, Energy Division also determined that the CCA that relinquishes all of its allocated capacity should file comments on the Tier 3 advice letter(s) of the CCA(s) receiving its programmatic capacity, thereby confirming this arrangement. Finally, Energy Division agreed with PG&E that discussion of project caps is more appropriately discussed in project solicitations, which PG&E accurately stated the maximum project size as 4.26 MW.

On July 23, 2020, D.20-07-008 was issued that directed PG&E to automatically enroll customers from a targeted population, based on prioritization of customers at high risk of disconnection within the existing parameters of program eligibility in the DAC-GT Program. Automatic enrollment is required for PG&E residential customers who meet the following criteria:

• Located in one of the statewide CalEnviroScreen top 15% census tracts located in PG&E’s service territory

• Eight or more late payment notices triggering three to six collection processes per year

• Two or fewer “Return to Maker” payments

• Two or fewer disconnections within 12 months

• Six or more payments within the last 12 months (indicating a customer’s effort to pay)

• “Total Balance Owing” is greater than $0 (with no credit balance on account)

PG&E shall automatically enroll eligible DAC-GT customers in its territory meeting these criteria until it reaches its capacity limit of 54.82 MW. After that, customers will be placed on a waitlist. This decision sought to meet the access-related objective of the ESJ Action Plan and helps reduce the financial impact of increasing bills and decreasing economic opportunity that results from the COVID-19 pandemic. Instead of applying this requirement for all IOUs, the decision only made this a requirement for PG&E, which is the only large electrical corporation ready to launch the DAC-GT program with its existing capacity.

Net Energy Metering (NEM) Paired Storage (R.14-07-002)

Interconnection

NEM paired storage is defined as qualifying energy storage devices paired with a eligible renewable generator that meet the RPS Guidebook requirements as an "addition or enhancement." According to the RPS Guidebook, there are two such categories of energy storage:

• Integrated storage are storage devices that are only capable of storing energy from the eligible renewable generator

• Directly connected storage are storage devices that are directly connected to the eligible renewable generator via an internal power line

On January 28, 2016, D.16-01-044 clarified that NEM "additions or enhancements" such as energy storage should be treated the same when it comes to interconnection as standalone NEM-eligible generators. The Decision cited D.14-05-033, which ruled that storage devices paired with NEM-eligible generation facilities are exempt from interconnection application fees, supplemental review fees, distribution upgrade costs, and standby charges.

See CESA's comments on January 7, 2016 on the Proposed Decision.

Metering Configurations & Options

D.14-05-033 established self-contained, single-phase metering requirements:

• “Large” systems (paired storage device > 10 kW-AC) are required to comply with metering requirements similar to those in the NEM Multiple Tariff (MT) Special Condition by installing a non-export relay or interval meters
  
  

• “Small” systems, (paired storage device ≤ 10 kW-AC) can use an estimation methodology to validate the eligible NEM credits
  
  

• Fees associated with this metering requirement are limited to $600 (exceptions apply for complex metering arrangements)

• Interconnection costs that the NEM generator would be required to pay would apply for the storage applicant pursuant to Rule 21

On October 18, 2016, PG&E and SCE proposed modifications to their NEM tariffs (i.e., Special Condition 11: NEM Paired Storage) that included changes to definitions, interconnection requirements, billing, and metering costs.

On November 4, 2016, SDG&E filed an Advice Letter that updated its NEM tariffs to implement the sizing, metering, and estimation methodology requirements for NEM-paired energy storage systems pursuant to D.14-05-033 and D.16-04-020

On December 28, 2016, SDG&E filed a Supplemental Advice Letter to include additional language to its NEM tariffs at the direction of the CPUC that modified the NEM and NEM-ST schedules to clarify that the $600 cap for metering costs does not apply to NEM-paired energy storage systems requiring “complex” metering. According to SDG&E, standard metering equipment is comprised of a single, self-contained, single-phase meter. 

CESA protested SDG&E's revisions to their Schedule NEM and Schedule NEM-MT to state that standard metering equipment only applies for NEM-paired storage configurations with a single meter, which would preclude DC-coupled systems from having their metering fees capped. CESA requested that SDG&E modify their Supplemental Advice Letter to consider complex metering equipment for NEM-paired storage systems that utilize more than two self-contained meters.

See CESA's protest on January 17, 2017 on SDG&E’s Supplemental Advice Letter.

On December 29, 2016, SCE filed a Supplemental Advice Letter to modify their Schedule NEM-MT to preclude "certain single-inverter systems" due to concerns about whether the energy storage device's output comes from the NEM-eligible generator or the grid. 

CESA protested that by installing an interval meter on the NEM-eligible generation, load, and total energy flows at the point of common coupling (Metering Option 2 from D.14-05-033), it is possible for DC-coupled systems to identify when a NEM-paired storage system is charging from the grid at any hour of the day, thereby resolving any "NEM integrity concerns raised by SCE. 

See CESA's protest on January 17, 2017 on SCE’s Supplemental Advice Letter.

On January 24, 2017, SDG&E replied to protests and agreed to modify the definition of standard metering to include up to two self-contained, single-phase meters, thereby ensuring that DC-coupled storage systems have their metering fees capped at $600. SCE also replied to CESA's protest stating that it had complied with D.14-05-033 and that the issue raised by CESA was out of scope in this advice letter filing. Instead, SCE said that the appropriate regulatory process would be to submit a Petition for Modification. 

On February 22, 2017, the CPUC approved SCE's and SDG&E's Advice Letters modifying its NEM tariffs to implement the requirements applicable to NEM-paired energy storage systems pursuant to D.14-05-033 and D.16-04-020. The CPUC determined that SCE and SDG&E were in compliance and therefore disposed of CESA's protests. SCE’s Supplemental Advice Letter to modify their NEM multiple tariff (NEM-MT) to preclude “certain single-inverter systems” is thus approved. SDG&E may still proceed with the promised changes to modify the definition of standard metering to include up to two self-contained, single-phase meters, thereby ensuring that DC-coupled storage systems have their metering fees capped at $600.

On September 1, 2017, CalSEIA filed a Petition for Modification (PFM) that seeks to modify D.14-05-033 to allow DC-coupled NEM-paired storage systems to interconnect under the NEM tariff. No metering option was adopted in D.14-05-033 for DC-coupled systems (i.e., NEM-paired storage systems behind a single inverter), which has created a barrier for these configurations. Given that there are no revenue-grade DC meters accepted by the IOUs at the moment, CalSEIA proposes two alternative options:

• No grid charging: CalSEIA proposes to use a device that controls the DC voltage of electricity entering the energy storage system and a charge controller that does not allow the battery to be charged below a set voltage (except to power auxiliary loads), which occurs when solar is not producing electricity. This device is proposed to similarly apply for VNEM-paired storage systems and AC-coupled systems. CalSEIA also discusses the possibility of using a non-import relay and DC-DC converter functionality.

• No storage export: CalSEIA proposes to use an inverter or charge controller with sensor-based functionality that prevents the storage device from discharging at times when the customer site is exporting power to the grid, or install an external relay that provides the same function. According to CalSEIA, this solution ensures that NEM credits are only received from exporting solar while allowing the paired storage device to only serve onsite load. In other words, if the energy storage system never exports, then any exports from the combined solar-plus-storage system can only come from solar, eliminating any concerns regarding NEM eligibility. This device is proposed to similarly apply for VNEM-paired storage systems and AC-coupled systems.

CESA supported the approval of CalSEIA’s PFM, but elaborated on how the door should be left open for other DC-coupled NEM-paired storage systems, and how CALSEIA's proposed alternatives are just two options, not the only ones. CESA also voiced support for the proposed adjustment to the sizing limitations for DC-coupled NEM-paired storage systems.

See CESA's response on October 2, 2017 on CalSEIA's Petition for Modification.

On July 19, 2018, a Ruling was issued to seek supplemental information on proposed software approaches to limit grid charging. CESA provided a general response in support of CALSSA's PFM and commented on the some of the advantages of software (over firmware) controls for verifying NEM integrity and how inverter manufacturers today have many measures in place to mitigate NEM integrity or safety concerns. With some standards development, data sharing, and auditing, CESA argued that some of the CPUC’s concerns may be addressed. All parties agreed that the primary advantage of using software rather than firmware settings is the ease of upgrading, customization, and replacement as well as the ability to use a single make and model of an inverter. CALSSA added that software is relied upon today in the Rule 21 interconnection process (e.g., ensuring that energy storage systems never increase customer peak demand). However, the IOUs believed this ease of changing operations was the reason why software controls could not be relied upon to provide the IOUs confidence that the system would not be programmed to create safety or NEM integrity risks. They added that the software solutions would increase the costs of monitoring software-enabled systems to ensure consistent functionality and to guard against cybersecurity risks (e.g., firmware typically uses a closed or proprietary architecture). Rather, each of the IOUs favored firmware solutions similar to the Phase 2 communication requirements for smart inverters. PG&E, however, seemed to be open to exploring software controls if they are third-party NRTL certified, in addition to certifying that the software settings are always on that setting.

See CESA’s response on July 30, 2018 on the Ruling

On October 5, 2018, a PD was issued that approved the use of both firmware and software controls (i.e., “power-control-based options) as alternatives to metering solutions to address NEM integrity concerns for DC-coupled NEM-paired storage systems. However, there were a few conditions attached to these approved control alternatives. For firmware controls (i.e., voltage control system), the PD determined that the firmware control under the “no grid charging” use case based on an interim testing procedures and the “no storage export” use case if the firmware provides “equal reliability and security” as a non-export relay. For software controls, the PD approved software options as long as they are capable of communication with Smart Inverter Phase 2 and Phase 3 communication-compliant inverters. Within 30 days of implementation of Phase 2 and Phase 3 communication requirements (February 22, 2019), the IOUs are directed to submit advice letters on how they will implement the software-based option (i.e., late March 2019). The PD also proposed to assess the size of the storage system in the context of DC-coupled systems based on the lesser of the continuous output capability of the storage system or the inverter power rating, similar to sizing assessments used in the SGIP Handbook. The PD, however, rejected CALSSA’s request to allow third-party metering in lieu of utility-owned metering, as third-party-owned metering is not currently prohibited. The PD also rejected the ex post data validation proposal to validate NEM integrity because it does not provide a sufficient degree of reliability.

CESA supported the PD but recommended that the software and firmware option use cases be allowed so long as NRTL certification is achieved. CALSSA also supported the PD and expressed some concerns for the firmware option around the subjectivity of defining functional equivalence to a non-export relay and for the software option around the need to just be capable of communicating data rather than requiring activation of this communication. Similarly, EFCA supported the PD for many of the same reasons and added that the software options be made available to AC-coupled systems as well. Meanwhile, the IOUs generally supported the firmware option, with only SCE expressing that other firmware control methods should not be precluded. However, they generally expressed doubts about the software option because of more work needed in the SIWG, as the current Phase 2 and Phase 3 requirements do not monitor storage discharge and exports, do not provide revenue-grade data, and do not ensure secure communications. On the sizing determination, all parties either requested more clarity or recommended changes to rely on spec sheet information (CALSSA) and to fall back on the inverter power rating if spec sheet data is insufficient (SCE).

See CESA’s comments on October 25, 2018 on the Proposed Decision.

On December 28, 2018, a PD was issued that made some small but important modifications to the original PD issued on October 5, 2018. The original PD was calendared for votes at three different CPUC meetings in November and December before being withdrawn. The PD was withdrawn to make several key modifications that will open up non-metering interconnection pathways for DC-coupled NEM-paired storage systems. The new PD approved the use of both firmware and software controls as alternatives to metering solutions to address NEM integrity concerns for DC-coupled NEM-paired storage systems, similar to the original PD, but also removed the conditions attached to these approved control alternatives. For firmware controls, instead of conditioning approval of the “no grid charging” use case based on an interim testing procedures and the “no storage export” use case if the firmware provides “equal reliability and security” as a non-export relay, the new PD agreed with CESA, CALSSA, and EFCA that upcoming NRTL certification (2020 NEC Section 705.13 [Power Control Systems] to be published as an addendum to UL 1741) should take care of these conditional concerns. This is an important modification that leverages a standards-based approach and removes subjectivity in establishing “equivalency” to non-export relay functionalities.

For software controls, the PD removed the conditional approval on whether these controls are capable of communication with Smart Inverter Phase 2 and Phase 3 communication-compliant inverters since IEEE 2030.5 does not have the ability to report information about how a device’s settings are configured. Instead, the IOUs are directed to require a device’s configuration file to be non-editable to address concerns of the IOUs around the flexibility and configurability of software-based options. This is a positive change, though there are still details that need to be provided on what is required to validate how the device’s configuration file is non-editable.

Additionally, the PD made a small modification to allow the energy storage system size of DC-coupled solar-plus-storage systems to be determined by the lesser of the inverter’s rated capacity and the maximum continuous discharge capacity listed on the device’s technical specification sheets, which provides flexibility in configurations where inverters are sized to the solar capacity, not the energy storage capacity. In other words, paired energy storage systems that are sized below inverter’s rated capacity would have more flexibility to be assessed for interconnection.

Finally, the PD was unchanged from the original PD in regards to rejecting ex post data validation proposal and the use of third-party-owned metering in lieu of an NGOM.

CESA expressed strong support for many of the changes to the PD, which largely fell our way. The only area of comment for CESA was around the need to ensure that subsequent advice letter filings ensure clear and efficient pathways for software settings to be edited as customer and grid needs change. CESA thus requested a stakeholder group to be convened to work through some of these implementation details. The IOUs generally expressed a concern that a national standard may not be published as expected in the PD. PG&E, however, added comments on the storage sizing matters. Specifically, PG&E indicated its intention to use the inverter capacity rating if spec sheets do not consistently list “maximum continuous discharge capacity” and how it will use the sum of ratings for multiple batteries paired with a single PV system.

See CESA’s comments on January 17, 2019 on the Proposed Decision

On February 5, 2019, D.19-01-030 was issued that approved the PD (issued on December 28, 2018) with only minor modifications to reflect how the publication of Certification Requirements Document (CRD) represents the approval of the national certification standard, to direct the CEC and stakeholders to establish common terminology for industry specification sheets on the Storage Equipment Lists, and to decline expanded applicability of the decision to AC-coupled systems. Overall, this was a great win for CESA members looking to utilize firmware and software controls to verify NEM integrity in NEM-paired storage systems, as opposed to using potentially costly metering solutions. With standards being quickly developed for firmware and software controls, the IOUs are becoming more comfortable with these metering alternatives. This decision is especially important for DC-coupled NEM-paired storage systems that have limited set of metering options under D.14-05-033. Concurrently, we are also seeing progress in the Rule 21 proceeding to facilitate DC-coupled NEM-paired storage interconnections, such as through the development of DC metering standards.

On March 8, 2019, a UL CRD was issued on UL 1741 (Power Control Systems) for 2020 NEC 705.12 that addressed both non-export and limited export, which means that inverters have the capability of being certified as capable of non-export and non-import.

On March 22, 2019, each of the IOUs also submitted advice letters to implement D.19-01-030, which among other things, made changes to the NEM tariff citing the new UL standard as a pathway to interconnection and to set a maximum response time of 10 seconds as the eligibility threshold to be equivalent to a non-export relay. CALSSA and Tesla submitted a response recommending that the advice letters be modified to allow customers and developers to submit an application that leverages operational controls prior to the project equipment being certified to the new UL standard since technology manufacturers will take 4-6 months to get certified to this standard, even as application approval would still be contingent on being approved to this standard. However, for PG&E’s advice letter, CALSSA and Tesla protested the requirement for verification of inverter settings prior to interconnection, which they found to be a separate issue that should be able to leverage whatever is developed for smart inverters or to accept a signed statement on the interconnection application. They also protested how PG&E limited the new interconnection requirements to DC-coupled systems as opposed to both DC-coupled and AC-coupled systems. In their response, SDG&E agreed to set a 10-second response time requirement similar to what was proposed by SCE. In addition, the IOUs agreed to allow a one-time modification of an existing interconnection request to change from NGOM to UL Power Control Systems and to allow developers to submit interconnection requests that are pending certified equipment under the UL standard. SCE specifically proposed a six-month interim period following the approval and implementation of the advice letters, where a permission to operate would not be issued until proof of certification is received.

On September 26, 2019, PG&E submitted a supplemental advice letter to allow the use of a new power control standard for NEM-paired storage interconnection but did not modify the response time required, which was proposed to be set at less than two seconds. Specifically, PG&E included improved tables clearly laying out the AC-coupled options within the integrated storage and directly-connected storage framework of D.14-05-033.

CALSSA and Tesla submitted a protest contending that PG&E continues to delay engaging with stakeholders to resolve the open loop response time required for certification or the process for demonstrating that a system has been installed with the proper settings. The CRD assumes that some applications of power control systems will require faster response times than others, with a maximum of 30 seconds, though allowing policymakers to set faster response times for specific use cases. The testing laboratory will specify a system’s response time in the test results. CALSSA pointed to SCE’s adoption of the 10-second open loop response time.

According to the Rule 21 Working Group, CALSSA explained that if the open loop response time is less than 2 seconds, the utility will consider the system as one that never exports in studying grid impacts. If the open loop response time is between 2 and 10 seconds, the utility will consider the grid impacts of inadvertent exports. For this reason, manufacturers are striving to achieve certification with a response time of less than 2 seconds. However, response times in the range of 3-5 seconds are more common in current product design. Two seconds may not be achievable at a reasonable cost.

On November 8, 2019, PG&E agreed to make most of the requested changes, including the changes around the open loop response time (i.e., inadvertent export for responses greater than 2 seconds but less than 10 seconds), and proposed to require additional documentation to verify the proper settings are in fact activated, including:

• Manufacturer documentation about the inverter capability, its control scheme with regards to the CRD, and its response time

• Once a standard is in place, they will rely on documentation that the inverter or applicable equipment was certified

• Documentation from the inverter manufacturer explaining what the specific inverter settings that are correspond to the relevant CRD requirements

• Documentation to confirm the inverter is set up and activated to meet the agreed-upon requirements

Sizing Limitations

D.14-05-033 placed some limitations on the size of energy storage systems paired with NEM-eligible generators:

• All NEM-paired storage systems with storage devices 10 kW or smaller are not required to be sized to the customer demand or NEM generator
  
  

• NEM-paired storage systems with storage devices larger than 10 kW will be required to have a maximum output power no larger than 150% of the NEM generator’s maximum output capacity
  
  

• For NEM-paired storage systems with storage devices larger than 10 kW, the discharge capacity of the storage system shall not exceed the NEM generator’s maximum capacity and the maximum energy discharged by the storage device shall not exceed 12.5 hours of storage per kW

  
  

On October 18, 2016, PG&E and SCE proposed modifications to their NEM tariffs (i.e., Special Condition 11: NEM Paired Storage) that included changes to definitions, interconnection requirements, billing, and metering costs.

On September 1, 2017, CalSEIA filed a Petition for Modification (PFM) that seeks to modify D.14-05-033 to allow DC-coupled NEM-paired storage systems to interconnect under the NEM tariff. CalSEIA recommended that the size threshold for the NEM estimation methodology be applied to the size of the storage devices in DC-coupled systems, rather than the inverter nameplate capacity, which is typically sized to the solar output. While AC-coupled storage devices have their own inverters, and thus inverter capacity serves as an appropriate proxy to determine this threshold, CalSEIA believes it is not appropriate for DC-coupled storage devices that will typically be sized to the onsite load and thus should use the continuous output value on the manufacturer’s spec sheet to determine whether it qualifies for the NEM estimation methodology.

On August 13, 2018, a PD was issued on August 13 that denied ABC Solar's PFM to modify the size criteria established in D.14-05-033 to allow its 10.8-kW NEM-paired storage system to operate in SCE’s service territory by increasing the size restrictions to 30 kW. This PFM was denied and the PD refuted the arguments using the 1-MW maximum size limit on NEM-eligible generation facilities in all cases by citing how each facility must also be sized no larger than the eligible customer-generator’s own electrical requirements, which is well below 1 MW for the average residential customer. The PD also rejected arguments connecting this denial of permission to operate to violations of the Solar Rights Act and consistency with SGIP size and metering requirements, which serves a different purpose (i.e., metering output versus ensuring NEM integrity). Overall, this PFM lacked much policy or factual justification and required no response from CESA.

On October 19, 2018, D.18-10-005 was issued that denied the petition for modification by ABC Solar to modify the size criteria by which D.14-05-033 imposes a size limit and metering requirements on NEM-eligible facilities paired with energy storage. This was unsurprising as the grounds for the petition did not bring up factual reasons to revise this policy and the petitioner generally did not follow proper procedures. The CPUC thus reaffirmed these requirements as limiting NEM credits to NEM-eligible generation.

Bill Credit Estimation Methodology

On April 21, 2016, the CPUC approved a Final Decision (D.16-04-020) that adopted a NEM bill credit estimation methodology for generating facilities paired with small energy storage devices (less than 10 kW). For small NEM paired storage, an estimation methodology can be used to cap maximum allowable NEM bill credits based on a monthly output profile. Production estimates are generated using the the Expected Performance-Based Buydown (EPBB) calculator used in the California Solar Initiative (CSI). Any exports exceeding this limit would not be eligible for NEM credits and would be forfeited. Peak period exports would be reduced first, followed by partial peak and off-peak as necessary. Alternatively, small NEM paired storage can elect to implement the NEM-MT metering provisions rather than utilizing the bill credit estimation methodology. 

Large NEM paired storage is billed consistent with the NEM-MT Special Condition, with the storage device treated as a non-NEM-eligible generator. 

D.16-04-020 set October 18, 2016 as the deadline for implementing these requirements.

See CESA's comments on March 25, 2016 and reply comments on March 29, 2016 on the Proposed Decision.

On September 13, 2016, PG&E requested a 12-month extension to implement the billing and IT requirements of D.16-04-020. PG&E points to long-term maintenance of the EPBB and justifies this request by developing customer estimates based on optimally-oriented PV systems and common-use systems. PG&E joins SDG&E in requesting this extension. 

On April 17, 2017, the three IOUs jointly filed a PFM to seek a simplification of the NEM bill credit estimation methodology for generating facilities paired with small storage facilities (less than or equal to 10 kW). The IOUs propose to use a pre-determined table based on climate zone and standard inputs, rather than individually calculated caps, to determine the maximum exports eligible for NEM credits when NEM generators are paired with small storage devices. The climate zone-specific estimation methodology would be based on a scalable 1 kW of PV installation based on the following assumptions using the Estimated Performance-Based Buydown (EPBB) calculator:

• Optimal tilt (20°)

• Optimal azimuth (180°)

• For each climate zone, identify the three zip codes with the most residential PV installations and choose the zip code with the highest generation estimate using the EPBB calculator

• Panel: SunPower: SPR-372NE-WHT-D

• Inverter: Enphase Energy: M215-60-2LL-S2X

• Mounting Method: > 6” average standoff (EPBB default)

• Shade: Minimal (EPBB default)

PG&E decided to request this relief because of the cost and complexity of the customer-specific methodology and due to unaddressed issues regarding non-bypassable charge (NBC) calculations. The difficulties also stemmed from missing PV specification information required for the EPBB calculator. Since the proposed methodology is based on optimal PV installations in each climate zone, CESA found no major issue with this PFM. SDG&E and PG&E will have until January 16, 2018 and SCE will have until March 18, 2018 to implement the estimation methodology.

On March 12, 2018, each of the IOUs filed advice letters implementing D.18-02-008 in their NEM tariffs to estimate bill credits for NEM-eligible facilities paired with small energy storage by using a single per-kW profile for each climate zone, in place of the customer-specific estimation using the EPBB calculator.

On June 14, 2019, PG&E submitted an advice letter clarifying their NEM tariff that customers that add storage to their existing NEM facility can qualify for the billing estimation methodology for storage systems less than 10 kW after going through their scheduled true-up via a manual tracking system. This was intended to close a gap in storage retrofits to existing NEM-only systems.

On June 18, 2020, D.20-06-004 was issued that denied the petition for modification (PFM) of Californians for Renewable Energy (CARE) and Michael E. Boyd, filed on August 23, 2018, requesting to eliminate the NEM bill credit estimation methodology in favor of monthly meter readings to establish a program that complies with rules and laws around Qualifying Facilities (QFs) less than 1 MW in nameplate capacity. The decision agreed with PG&E that customers with small solar-plus-storage systems currently have the option to take service on a NEM-MT tariff, which provides for monthly meter readings as requested by Petitioners. Furthermore, the decision referenced Public Utilities Code Section 366.2(a)(5) in highlighting how CCAs are solely responsible for generation procurement activities for their customers and thus the CPUC cannot dictate the net surplus compensation rate offered by a CCA (i.e., the rate can be different from those offered by the IOU on their NEM tariff).

Solar Savings Calculator

On July 18, 2019, the CPUC Energy Division staff developed a proposal, as attached in a Ruling, that calculates estimated electric utility bill savings from a solar energy system that a residential consumer can reasonably expect during the first 20 years following interconnection of the system. The standardized inputs and assumptions that all solar providers would need to use were proposed as follows:

• Estimated annual electricity consumption: Assume that the consumer’s electricity usage profile during the prior 12 months on the relevant interval basis (e.g., one-hour intervals for most residential IOU consumers) will be equivalent to the consumer’s annual electricity consumption each year for 20 years following interconnection. However, not all customers may have 12 months of one-hour interval consumption data.

• Assumed rate schedule: When calculating a no-solar scenario, assume the consumer would stay on their current electricity provider rate. When calculating a scenario where the consumer installs and interconnects a solar energy system, assume the consumer will choose an applicable rate tariff (e.g., NEM successor tariff on a TOU rate).

• Assumed solar electricity generation: Use PVWatts to calculate the future generation of PV panels.

• Average escalation of residential retail rates: Assume that average electricity rates of the relevant electricity provider will increase at a rate equivalent to the average of its rate increases over the past five years based on the most recently available EIA data, and then select an escalation rate that is within 2.12% above or below this calculated average escalation rate.

• Assumed annual degradation rate: Assume that the average rate at which the PV system (panels/inverter) generates less electricity per year based on the physical degradation of the system over time is equivalent to the degradation rate listed in the panel/inverter manufacturer’s technical specifications.

The estimated electric bill savings must be provided by the solar provider in the Contractors State License Board’s Disclosure Document. Upon request by either the consumer or by CPUC staff, solar providers will be audited and must provide consumers and the CPUC with a detailed accounting of how the calculation was performed. To develop the tool, staff proposed a two-phase process for implementing AB 1070:

• Phase 1: Define standardized inputs and assumptions to be used in the calculation of bill savings for prospective solar consumers.

• Phase 2: The CPUC will execute a contract with a third-party to develop an online estimated electric bill savings calculator that can be used by solar providers, prospective residential consumers, and the public at-large to calculate estimated electric bill savings. The second phase will also include a revisit of the calculation and make necessary refinements (if necessary).

On August 13, 2019, a workshop was held to build an understanding of the standardized inputs and assumptions for calculating electric utility bill savings from the use of a solar energy system. CPUC staff discussed how the calculation will be developed to allow for battery storage “generation” to be overlaid on top of it, but the CPUC staff wondered whether the inclusion of battery storage creates any problems for this bill savings calculation.

CESA expressed how this proposal should account for paired storage given market trends, new TOU periods, and default TOU rates for all residential customers in 2019 and 2020. Standardized operating assumptions for rate arbitrage should be used while allowing for customizable but verified inputs from the CEC’s Storage Equipment List to build the storage overlay. Finally, CESA recommended that the CPUC frame the bill savings calculator inputs as reference cases for consumer protections but allow vendors and providers to provide a site- and customer-specific estimates that account for field conditions, financing and contracting approaches, and additional revenues or savings from providing incremental grid services.

See CESA’s comments on August 27, 2019 on the Ruling and Staff Proposal

CALSSA and SEIA was alone in opposing the savings calculator altogether, explaining how standardized inputs and assumptions may be inaccurate and how a tool would have a short shelf life. However, the IOUs and ratepayer advocates opposed the ability for vendors to develop their own forecasts except with the use of standardized inputs and assumptions, even as a reference or alternative case as CESA, CALSSA/SEIA, and Aurora suggested. In addition, most parties agreed with CESA’s suggestion to incorporate storage, but that it is premature at this time –i.e., it should be incorporated in the next phase of the calculator.

On February 10, 2020, a Ruling was issued that confirmed the applicability of the calculator and its associated inputs to all NEM or non-NEM residential PV customers, thereby extending the scope of the calculator to include BVES customers.

On August 13, 2020, D.20-08-001 was issued that adopted a modified staff proposal requiring that every solar provider who intends to enter into a photovoltaic solar transaction with a residential customer in the state of California (except for new housing construction where a solar system is installed prior to sale) calculate and present estimated electric bill savings to the customer for the first 20 years from interconnection, using the staff proposal’s standardized inputs and assumptions. The most significant revision is to the average escalation of electricity provider residential rates was to remove the option to select an average escalation rate above or below the average inflation rate, instead limiting the maximum assumed escalation rate to 4% in order to avoid providers inflating bill savings by assuming higher future electricity prices.

This standardized calculation must be included in the supporting information pages of the Solar Energy System Disclosure Document – another requirement intended to provide solar consumers protections. If a solar provider presents a bill savings estimates to a customer prior to the point of sale, this standardized calculation must be presented to the customer at that time as well. Any bill savings estimate should be accompanied with language regarding the inherent uncertainty of such estimates, especially those spanning any timeframe longer than one year. Customers should also be allowed to make their own estimates using a publicly-available online calculator, and solar providers are allowed to offer their own savings estimate. In response to comments from the solar associations opposing this requirement premised on how the CPUC lacks such jurisdiction, the decision asserted that the CPUC has an objective to protect consumers and has jurisdiction over the utilities’ interconnection processes. Notably, new home construction is exempt from a mandatory savings claim. The requirements would be effective 120 days after the issuance of the final decision (December 11, 2020). Phase 2 of AB 1070 implementation will focus on executing a contract with a third-party to develop the online calculator and to potentially revisit the calculation for any necessary refinements.

In response to the PD, the IOUs and solar parties, however, objected to the scope of the proposed citation program to include fines or other penalties regarding the required electric bill savings estimate disclosures adopted in this decision because the entire enforcement framework is being challenged by the IOUs in a separate PFM filing. CALSSA and SEIA added that access and use of interval data is needed to make best use of the calculator (e.g., one-click authorization for Green Button Data), but if historical data is not attainable, alternatives should be allowed, such as requiring the solar provider to baseline a 365-day, 1-hour interval data file for the homeowner based off a credible and typical residential load profile (e.g., NREL data for all TMY3 locations). SEIA recommended some modifications to remove the 4% cap on the escalation rate, allow the use of stock load profiles by climate zone in lieu of customer-specific historical usage data, and allow solar providers to rely on the degradation rate listed in a manufacturer’s warranty in lieu of using the one listed in manufacturer’s technical specification. Finally, TURN was a major critic of the PD for diluting the purpose and impact of the calculator by allowing for alternate estimates, where if allowed, vendors should be required to clearly and affirmatively disclose all material differences that affect savings outcomes. Relative to the PD, the decision was modified to clarify the side-by-side comparison between standard and alternative calculations, the fact that source codes will not be collected by the IOUs, requirement to retain copies of inputs and assumptions (rather than uploading them), and potential enforcement mechanism if and when developed.

Net Energy Metering Successor Tariff (R.14-07-002)

Background

AB 327 is a multi-part bill that affects a number of aspects of regulated utility service and of the energy market, including NEM. The CPUC opened a rulemaking proceeding to develop a NEM successor tariff that will address existing issues in the current NEM program as well as a NEM successor tariff to be finalized by December 31, 2015. The current NEM program expires at the earlier of: (1) July 1, 2017; or (2) NEM total rated generating capacity of 5% of the IOUs' aggregate peak demand. 

On July 10, 2014, the Order Instituting Rulemaking (OIR) was issued that started this proceeding to develop a successor tariff to the NEM program authorized in Section 2827. 

NEM Successor Tariff 2.0

On January 28, 2016, a Final Decision (D.16-01-044) adopted a NEM successor tariff that essentially rejected many of the proposals by the utilities and other parties (which included varieties of demand charges, fixed charges, and standby charges) and preserved the current NEM tariff with a few modifications. Given the default residential TOU rates coming in 2019 and ongoing work to quantify the benefits of DERs in other proceedings (e.g., DRP and IDER), D.16-01-044 expressed concern for how much change NEM customers could absorb in the near term. D.16-01-044 also maintained annual true-up periods. Below is a summary of the key changes of the "NEM 2.0 Decision" for customers subscribing under the NEM Successor Tariff:

• Retail rates: Maintained full retail rate compensation for exports

• Nonbypassable charges (NBCs): Required to pay NBCs (e.g., public purpose programs, nuclear decommissioning, water resource bonds) on total, not net, amount of electricity the customer obtains from the utility (adding costs of about $0.03/kWh or $6-8/month to NEM 2.0 customers)

• Interconnection fees: Eliminated interconnection fee exemptions and must now pay "reasonable" interconnection fees (usually between $75-100 for systems under 30 kW)

• TOU rates: Must take service under one of the IOUs' residential TOU rates available to them

• Virtual NEM: Maintains programs elements but with similar NBC payment requirements and removal of interconnection fee exemptions

• Grandfathering: Grandfathered onto the NEM Successor Tariff for 20 years (similar to NEM 1.0 customers)

After the implementation of default TOU rates in 2019, all residential NEM Successor Tariff customers must take service under TOU rates, regardless of their date of interconnection. The NEM successor tariff will be reviewed again by the CPUC in 2019.

See CESA's comments on September 1, 2015 on parties' proposals.

On June 30, 2016, SDG&E became the first California IOU to hit its NEM cap, which limits distributed generation projects eligible for NEM to 5% of its peak demand. New SDG&E customers will be subject to the NEM successor tariff.

On September 29, 2016, the CPUC denied the challenges seeking rehearing of the NEM successor tariff by TURN and the Coalition of California Utility Employees (CUE). The protesting parties argued that the successor tariff results in unlawful cost-shifting and cross-subsidization. The CPUC, however, determined that there is insufficient evidence to estimate the extent and amount of cost-shifting. 

On December 15, 2016, PG&E reached its NEM cap, which triggered the switch to the NEM successor tariff. Only customers who provided complete interconnection applications prior to PG&E reaching the capacity cap will be able to take service under the old NEM tariff.

On May 19, 2017, CALSEIA, Multifamily Affordable Solar Homes (MASH) Coalition, and Everyday Energy submitted a Petition for Modification (PFM) of D.16-01-044 to address the potential harmful impacts that mandatory TOU may have on tenants of multifamily affordable housing that receive NEM credits through virtual NEM (VNM). These joint parties conducted an analysis of TOU data from SCE and found that it would create high variability and increase monthly electricity bills by 87% for more than 25% of the analyzed accounts. The PFM points to the high capital costs of storage, lack of differentials in TOU rates, and difficulty in getting utility approval for storage at multifamily properties under VNM.

On June 28, 2017, PG&E filed an Advice Letter indicating that it will make Peak Day Pricing (PDP) available to eligible NEM customers on an opt-in basis effective July 1, 2017. 

On July 1, 2017, SCE was switched to the NEM successor tariff, even though it had not reached its cap. As of June 2017, SCE was 314 MW away from its cap. This date was set as the deadline to switch to NEM 2.0 if it had not been triggered by NEM installations. 

On April 25, 2019, Resolution E-4991 was issued that approved modifications to NEM provisions for customers affected by natural or man-made disasters, including:

• Authorized PG&E to remove the system modification threshold for disaster-impacted NEM customers and allow replacement systems to be sized to new annual load without requiring customers to take service on the NEM2 tariff

• Authorized PG&E to modify its NEM2 tariff to allow disaster-impacted NEM2 customers to size replacement systems to the annual load of the new premises

• Authorized PG&E to exempt disaster-impacted NEM2 customers from the interconnection application fee when re-applying for service on the NEM2 tariff, as long as their replacement systems are sized to their new annual load and no greater than 1 MW

• Authorized PG&E to update its interconnection application forms to provide a means for disaster-impacted customers to identify themselves during the interconnection process and benefit from the revisions above

• Ordered PG&E to extend the proposed relief to customers on NEMV Tariffs, including standard NEMV, NEMVMASH, and the successor NEM2V and NEM2VMASH tariffs

This Resolution provided reasonable and fair relief to customers affected by the 2017 wildfires who seek to rebuild homes as well as associated rooftop PV systems.

On May 6, 2019, D.19-04-019 was issued resolving the application for rehearing filed by SDG&E, SCE, and NRDC over how best to interpret D.16-01-044 regarding assessment of NBCs under NEM successor tariffs. The decision clarified the determination in Resolution E-4792 that NBCs shall be assessed on the net kilowatt-hours consumed in each metered interval, and not on the basis of instantaneous netting (i.e., registering of net energy usage from one instant to the next, and not based on netting energy usage over a 15-minute or hourly interval) under the NEM successor tariff. While second-by-second, or instantaneous, measurement enables a more accurate tally of the amount of net imports and net exports over a given time period, the decision explained that language in D.16-01-044 around “in each metered interval” was not merely incidental or a result of cautious drafting. The pivotal change in D.16-01-044 was to shorten the duration over which imports and exports should be netted, from monthly to each metered interval, in order to significantly increase the amount of available kWh on which to pay the NBCs, relative to when such charges were assessed only on the monthly netted-out volume of electricity consumed from the grid.

On June 21, 2019, PG&E submitted an advice letter to clarify how NEM customers impacted by disasters can resume service under their original NEM agreement. For VNEM customers, PG&E explained that this is more complicated than single NEM customers as there are often many other beneficiaries in addition to the building owner or operator under VNEM arrangements. To address this, PG&E proposed to allow VNEM customers to remain on their original VNEM agreement if the building owner is the same, the replacement generating facility adheres to sizing limitations (i.e., no more than 12 months of historic or estimated kWh usage), the new VNEM facility exists on the same parcel it was originally located on, the solar energy credit allocation percentage ratio between Common Area and Residential Unit must be the same or greater if the 5-year fixed allocation requirement has not yet been met, and the intervening period from the destruction of the generator in the disaster to the issuance of PTO for its replacement must be no longer than two years.

Program Evaluation

On December 6, 2019, a workshop was held to provide a forum for the selected consultant (Itron) to present a draft research plan for the NEM 2.0 Program Evaluation, which will analyze the costs and benefits of customer-sited renewable resources taking service on NEM 2.0 and its variants. Itron proposed that the NEM 2.0 evaluation will be divided into three main areas:

• Analysis of NEM 2.0 systems: Itron will collect utility interconnection data to define the population of NEM systems interconnected through the end of 2019 to understand whether systems installed under NEM 2.0 are materially different from NEM 1.0 systems in size, orientation, or otherwise.

• Cost-effectiveness analysis of NEM 2.0: Itron will build a model that quantifies the cost-effectiveness of NEM 2.0 for participants, non-participants, Program Administrators, and society based on the Standard Practice Manual tests and consistent with CPUC D.19-05-019. This aspect of the evaluation will include an analysis of generation and storage charge/discharge data, clustering analysis of utility billing and interval load data, and cost of service analysis of NEM 2.0 to compare the actual bill payments that NEM 2.0 customers make as compared to costs needed to the costs to the utility to serve the customers.

On February 26, 2020, the CPUC approved a final research plan for the NEM 2.0 Program Evaluation to inform the development of NEM 3.0 tariff, which should kick-off in the middle of 2020. In response to comments from parties, the evaluation plan was revised to incorporate integration costs (e.g., flexible ramping) in the analysis but determined that incorporating other costs (e.g., avoided fuel volatility, avoided methane leakage, resiliency, GHG abatement) are out of scope of this study, which is better addressed in Avoided Cost Calculator changes. In addition, instead of using different marginal costs and hourly allocations from recent general rate cases, Itron opted to use already approved values in the cost analysis.

Solar on Multifamily Affordable Housing (SOMAH) Program

Background

AB 693 requires that the CPUC establish programmatic goals, participation criteria, administration, funding, and other elements for a financial incentive program focused on the installation of solar PV systems on multi-family affordable housing properties. The AB 693 Program is a $1-billion, 10-year program funded through cap-and-trade proceeds. 

AB 693 Implementation

On July 8, 2016, a Ruling was issued seeking proposals to implement AB 693, which will be the focus of the second phase of this proceeding. The Ruling included two questions related to how paired energy storage should be treated under this program. CESA cited statutory definitions, regulatory decisions, and federal/state policies to justify the program eligibility of energy storage. CESA also made the economic, environmental, and grid resilience case for program eligibility for energy storage systems and EV chargers paired with solar PV systems in the AB 693 Program. While CESA refrained from proposing a specific incentive structure for energy storage systems and EV chargers, CESA advocated for a carve-out within the program to pair a minimum MW level of energy storage systems with solar PV generation and requested that the CPUC pursue further examination and deliberation in this proceeding to firmly establish a viable incentive structure. 

See CESA's comments on August 3, 2016 and reply comments on August 16, 2016 on the Ruling.

On December 14, 2017, D.17-12-022 was issued that adopted a new Solar on Multifamily Affordable Housing (SOMAH) Program as a vehicle for implementation of AB 693 (Eggman, 2015) and provided the framework for the program’s implementation, including its goals, eligibility requirements, program administration, funding, and guidance for selecting a statewide Program Administrator. This program is similar but has different rules and eligibility requirements as the Multifamily Affordable Solar Housing (MASH) Program. Funding for the program will come from using a percentage of proceeds from the sale of GHG allowances. Pursuant to AB 693, the program has an overall target of installing at least 300 MW of solar on qualified properties (according to Section 2852(a)(3)(A) and Section 2870(a)(3)) by 2030 with an annual budget up to $100 million across the three IOUs. The new SOMAH program will provide upfront, capacity-based incentives for the installation of solar generation projects sited on existing affordable housing that ensures that at least 51% of bill credits from NEM generation accrue to the tenants of participating buildings. The incentive levels will decrease by the annual percent decline in residential solar costs as reflected in NREL reports, or 5% annually, whichever is less. Notably, the decision sided with the non-IOU parties by determining that it is reasonable to exempt participating tenants from the requirement applying to other customers using the NEM successor tariff to take service under a TOU rate. The decision found that the grid impact of this exemption would be minimal.

The impact of this decision on CESA members is not significant, except to the degree that there may be synergies between SGIP Equity Budget projects with solar projects with funding support from the SOMAH program. The consistency of eligibility requirements across the two programs allow for potential solar-plus-storage projects to take advantage of both programs, but there may be challenges related to the economic value proposition of energy storage additions given the TOU exemptions approved in the decision. In comments on November 20, SCE recommended that the SOMAH program give priority to program applicants from customers who are participating in the SGIP Equity Budget or those that install EV charging stations to serve their tenants. IREC took a more moderate position of seeking clarification that energy storage paired with solar is eligible for the SOMAH program. Previously, CESA also advocated for energy storage deployment incentives for low-income and disadvantaged community customers be run through the eventual AB 693 program, but with the new Equity Budget in place to play that role, the SOMAH program is less relevant to CESA members.

On February 13, 2018, a workshop was held in compliance with D.17-12-022 to designate a VNEM tariff for use by participants in the newly established SOMAH Program. The IOUs are required to file an advice letter that may modify an existing VNEM tariff used for the MASH program, or may develop a new VNEM tariff, as appropriate. Overall, the workshop covered the current state and structure of VNEM tariffs across the IOUs and discussed the goals and principles of the VNEM tariff for the purposes of the SOMAH program, with the IOUs favoring approaches that would focus on minor modifications and avoid complex or costly system changes.

On July 11, 2019, D.19-07-004 was issued that approved the exclusion of SOMAH participants from default TOU rates. 

On May 13, 2020, CALSSA, Brightline Defense Project, and Sunrun jointly submitted a Petition for Modification (PFM) to modify D.17-12-002 to support keeping SOMAH incentives at current levels due to the ITC stepdown, lower than expected solar cost declines according to NREL data, and a dearth of data regarding the costs of solar on multifamily affordable housing. Specifically, the joint petitioners requested that the CPUC clarify the PA’s obligations to correctly adjust the incentive levels as of July 1 of each year. The IOUs responded that the PFM does not present any new facts or meet the procedural requirements (i.e., filing more than one year after D.17-12-002 issuance).

SOMAH Program Implementation

On March 14, 2018, each of the IOUs filed advice letters to implement new SOMAH tariffs that are modeled after the existing VNEM tariffs. Only Everyday Energy filed a protest with regards to how the IOUs will make this tariff available through June 30, 2026, while Everyday Energy contends that the statute stipulates that these incentives should be made available to qualified multifamily affordable housing properties through December 31, 2030. In other news, the CPUC awarded the program administrator contract for the SOMAH Program to the Center for Sustainable Energy (CSE), GRID Alternatives, and the Association for Energy Affordability. Given the growing synergies of the SOMAH Program with SGIP and other storage-specific programs focused on low-income and DAC customers, this is a positive development.

On June 11 and 22, 2018, SCE and SDG&E filed supplemental advice letters that added a 20-year minimum duration for the generation allocation split to ensure that SOMAH program system benefits primarily accrue to participating program tenants - a change from its initially established 5-year minimum duration. In addition, they made a change to allow multiple generator accounts on a single allocation request form and to specify that customers are enrolled in Net Surplus Compensation by default. 

On June 21, 2018, the CPUC held a webinar on introducing the SOMAH Program.  Participants learned about the statewide program administration team’s unique community-based approach and got an overview of the program basics (e.g., eligibility) and timeline for implementing the program.

On July 12, 2018, a workshop was held on July 12 to discuss the Draft SOMAH Program Handbook. The SOMAH PAs discussed how the SOMAH Program is intended to coordinate with other clean-energy-related programs such as SGIP. There was a lengthy discussion about technical assistance implications on the reservation process and timing, investor approval, and structural engineering due diligence. Some parties commented about how the IOU requirement for an additional production meter for VNEM facilities may be unnecessary.

On October 1, 2018, the Final SOMAH Program Handbook and the SOMAH Program Implementation Plan was submitted to the CPUC via advice letter for finalization. The SOMAH PAs have experienced some delays in implementation due to the challenges in completing the solar sizing tool and the need to make important modifications to the Draft SOMAH Program Handbook in response to many stakeholder comments.

On April 2, 2019, Resolution E-4987 was issued that approved the SOMAH Handbook with modifications that would clarify the 18-month eligibility window, publish incentive budgets for each IOU, flag projects that have or plan to have EV charging station installations. Interestingly, the CPUC maintained that EV charging load should be considered common area load since EV charging is installed for tenants’ use and that access to such charging infrastructure is a tenant benefit. The CPUC also sided with CSE in finding that providing information about energy storage technologies and TOU rates should be allowed. In response to comments, the CPUC rejected recommendations from the IOUs to require 100% of SOMAH projects to be inspected by third parties. The SOMAH Handbook became effective May 9, 2019.

On July 1, 2019, the program launched. Funding was set to be renewed between December 2019 and February 2020 for all territories, including those which were waitlisted. 

On December 16, 2019, CSE submitted an advice letter, on behalf of the SOMAH PA team, to propose SOMAH Program Handbook revisions to limit participation of a PV project to one, but not both, of the SOMAH and MASH Programs. This was in response to the direction of the CPUC Energy Division. Sunrun protested the advice letter as being procedurally improper while PAO believed this was appropriate within statute and for program evaluation purposes.

On December 27, 2019, a Ruling was issued that proposed criteria for determining whether revenues are available and whether there is adequate interest and participation in the SOMAH Program for the purpose of authorizing the allocation of funds to the program through June 30, 2026. The Ruling noted that the program’s July 1, 2019 launch saw an immediate enrollment rush, so the IOUs are directed to submit accountings of how funds were disposed since 2016 to address the “missing funding” problem. PacifiCorp requested additional time to assess customer interest while SDG&E discussed how upwardly trending GHG revenues should be sufficient to cover the program going forward. SDG&E also noted that the program should await the independent evaluator’s report to verify the achievement of goals and the program’s cost effectiveness. Sunrun and CEJA recommended continued funding given the significant waitlist demonstrating interest in the program while contesting the continuation decision to be based on evaluation of the entire program instead of the two statutorily-mandated factors (e.g., assessment of revenues and interest/participation). Finally, Sunrun pushed for a modification of the definition of DACs for the purposes of the SOMAH Program, which the IOUs opposed due to inconsistencies that would create in DAC eligibility in other current and future incentive programs, and recommended establishing a six-month grace period for project eligibility when the CalEnviroScreen tool changes to give solar projects going through the sales process with adequate time and flexibility to submit applications, which the PAs supported.

On April 23, 2020, D.20-04-012 was issued that found there was adequate participation and interest in the SOMAH Program, thereby finding it reasonable to continue authorization of allocation of funds through June 30, 2026. To make this determination, the decision pointed to the evidence of the volume of projects on the waitlist and the rendering by the US Department of Housing and Urban Development (HUD) that the majority of HUD properties in California are eligible for the SOMAH Program. The decision, however, would not reach a finding program performance since the program commenced less than a year ago on July 1, 2019, though the CPUC encouraged continued efforts in marketing, education, and outreach (ME&O) as well as reporting and metrics to ensure equitable distribution of funds. Compared to the PD, only minor modifications were made. No party opposed the PD, with Sunrun and CSE explicitly supporting the PD, but Sunrun recommended that the CPUC set annual renewal and step-down structure for incentives. The CPUC recommended a Petition for Modification of D.17-12-022 to make changes in line with Sunrun’s recommendations.

On June 5, 2020,  Resolution E-5054 was issued that approved CSE’s proposed revisions to the SOMAH Program Handbook to provide explicit language clarifying that PV projects that have previously received a MASH Program incentive are ineligible to receive SOMAH Program incentives for the same system. The CPUC cited MASH Handbook language around discounting when ratepayer-funded incentives are stacked. The CPUC noted that the use of IOU GHG auction proceeds as clean energy program incentives is equivalent to ratepayer-provided funding.

On July 1, 2020, Sunrun submitted an Application for Rehearing (AFR), claiming that Resolution E-5054 unlawfully affects a modification of D.17-12-022 without following the proper procedures and adopts an arbitrary and capricious prohibition.

Virtual Net Energy Metering (VNEM) (R.14-07-002)

Background

VNM was first allowed in California's IOU territories in 2009 as a design feature of the Multifamily Affordable Solar Housing (MASH) program, and was soon added as an option to affordable housing properties utilizing the state's New Solar Homes Partnership (NSHP) program. 

On October 20, 2008, D.08-10-036 established the VNEM tariff that requires each utility to allow for the allocation of NEM benefits from a single solar energy system to all meters on an individually metered multifamily affordable housing property, without adversely impacting building tenants. This decision, however, is silent on whether a VNEM system may serve on-site load. It states that the utility would be required to meter solar system output separate and apart from metering of individual tenant and common area consumption in order to measure the NEM system's production/output as the baseline against which to compare the sum of consumption across several meters. 

On July 14, 2011, D.11-07-031 expanded the scope of VNEM to include any multi-tenant and multi-metered complex that was behind a single service delivery point (SDP) and to include those properties in a complex with multiple SDPs. The SDP is the demarcation between the customer-owned electrical system and the utility distribution system. This decision now allowed affordable housing developments that contain multiple buildings that connect to the utility distribution system at multiple SDPs to qualify for VNEM. This decision also expanded VNEM to all multitenant properties in California, both market rate and low income, regardless of their participation in the MASH program, but limited non-MASH projects to a single SDP. 

In 2016, D.16-01-044 further expanded VNEM to allow multiple service delivery points at a single site for all property types. These programs will also be subject to the changed application of nonbypassable charges and new interconnection fees as other NEM 2.0 customers. 

In VNEM systems, the solar generator is connected on the utility side of the customer meter. A separate generation-only meter is installed to measure the amount of solar generation that will result in NEM credits that are virtually applied to service accounts on the NEM property. Power only flows from the solar system to the grid (not to onsite load) because there is no load to serve on the customer side of the generation meter. Furthermore, like traditional NEM customers, a VNEM generator is sized to load, up to a maximum size of 1 MW, but it cannot have any other load behind its output meter. A customer can also only have one generating account and not have any electrical loads at the property tied to it. The same sizing, metering, and NEM integrity requirements apply for VNEM-paired storage systems. 

There are two tariffs that apply for VNEM systems:

• Schedule NEM-V is applicable to qualified customers on TOU rates whose service accounts are located on a multi-tenant property on the same premise of an eligible generator. All energy produced by the eligible generator(s) is supplied to the IOU for the sole purpose of providing monthly allocated credits to local benefiting accounts.

• Schedule MASH-VNM is applicable to residential multi-family affordable solar housing where all of the real property and apparatus are employed in a single low-income housing enterprise on contiguous parcels of land, which may be divided by a dedicated street, highway, or public throughfare/railway so long as the parcels are otherwise contiguous and part of the same low-income housing enterprise, and are under the same ownership.

VNEM allocates credits as the product of the kWh measured and the percent allocation to the benefiting account, one for tenant and one for common loads. The VNEM system is a "net consumer" if the energy consumed from the grid is greater than the allocated credit, and is a "net producer" if the allocated credit is greater than the energy consumed from the grid. A grid-connected NGOM meter is required and must be capable of measuring the flow of energy in two directions. No additional load other than the incidental load related to the inverters and support of the eligible generator may be registered on the meter. Net surplus compensation applies if the customer is a net producer over the course of the relevant period (usually one year). To calculate the net surplus compensation, you multiply the net allocated energy by the wholesale DLAP.

As part of the VNEM application and interconnection agreement, the owner must submit a list of all benefiting accounts and the percentage of total output that each benefiting account is to receive. Allocations are based on the percentage of total output and must remained fixed for participants for five years. Benefiting accounts receive retail credit for kWh of renewable generation as a line-item on their electricity bill on a monthly basis for their net consumption of electricity. If a benefiting account receives more bill credits than consumed in a given month, they are applied to another month's electricity charge within that annual billing year. If over a full billing year a benefiting account receives more generation that consumed, then the account will receive payment at the NSC rate.

Rules and models may vary, but a landlord can recover the cost of investing in a VNEM generator by allocating electricity to all or some units, and factoring the system's cost into the rent charged to new tenants. Generally, participation in VNEM must be opt-in. 

VNEM-Paired Storage

On August 14, 2017, a Ruling was issued seeking comment on how to revise the VNEM tariffs to make paired energy storage more accessible to VNEM customers. Energy storage is excluded from the VNEM tariff because VNEM generators are only allowed to export (not serve onsite load), which would apply for a paired storage system as well. However, a NEM-paired storage system is not allowed to export to the grid at times the NEM-eligible generator is not producing energy. The Ruling proposes two potential alternatives where the paired storage device under the VNEM tariff would:

• Be required to install a non-import relay (Alternative #1), or

• Be limited to discharge up to the aggregate customer demand of all the customers participating in that VNEM arrangement in that interval (Alternative #2)

CESA supports the CPUC's efforts to address this issue, but disagrees with the interpretation of two key decisions in the NEM proceeding, which are the foundation for the proposals in the Ruling. CESA also recommended that the CPUC address the fundamental issue of not allowing for any other load behind the output meter of the VNEM generator, and voiced its support for Alternative #1 but not for Alternative #2.

See CESA's comments on August 30, 2017 on the Ruling.

On August 16, 2017, a Ruling was issued requesting data from the IOUs related to potential rate impacts of mandatory TOU rates on certain VNEM customers. This is in response to the Joint PFM filed by CalSEIA, Multifamily Affordable Solar Homes (MASH) Coalition, and Everyday Energy on the need to revise D.16-01-044 to exempt multifamily affordable housing customers on VNEM tariffs from mandatory TOU rates. Responses to the Ruling were filed on September 15 by each of the IOUs that calculate hypothetical bills for all its MASH-VNEM customers with a full year’s worth of data under five different rate scenarios, including one with VNEM credits, one without VNEM credits, and one with a TOU rate schedule and VNEM credits. Overall, SCE and PG&E found that being on TOU rates produced benefits to all MASH-VNEM customers except for a very small percentage of them. SDG&E responded to the Ruling as being unable to conduct the data analysis requested until new software functionality is implemented.

On November 13, 2017, a PD was issued on November 13 that adopted modifications to the IOUs’ VNEM tariffs to facilitate pairing with energy storage systems. CESA supported the adoption of Alternative #1 but sought modifications to allow for non-physical import relay functions and/or data sharing provisions to also be allowed under the VNEM tariff to facilitate energy storage systems to be paired with VNEM generators. CESA also offered comments on whether never allowing for charging from the grid by VNEM-paired energy storage systems is the desired long-term policy outcomes, as there are resilience and backup power benefits of allowing for this, so long as billing or other mechanisms are in place to protect NEM integrity.

See CESA's comments on December 4, 2017 on the Proposed Decision.

On December 21, 2017, D.17-12-005 was issued that adopted modifications to the IOUs’ VNEM tariffs to facilitate pairing with energy storage systems. Specifically, the decision approved the installation of a non-import relay to ensure NEM integrity, but acknowledged that this solution needs to be enhanced to allow energy storage systems to consume a minimal amount of grid energy to power their control systems. In their comments to the Ruling, SCE proposed setting a threshold amount in any single billing interval beyond which NEM credits would be forfeited for that billing cycle. Given this unresolved issue, the decision directed the CPUC staff to hold a public workshop on identifying a means to implement Alternative #1 with minimal cost and complexity. The decision included an important clarification in response to CESA’s comments that modified Alternative #1 to allow for non-physical import relay functions, subject to any third-party certification or other standards, to also be allowed under the VNEM tariff to facilitate energy storage systems paired with VNEM generators.

On January 22, 2018, a workshop was held to discuss implementation of D.17-12-005 and to seek clarification on the following issues:

• The nature of the mechanism for pairing energy storage with a VNEM generator that is functionally equivalent to a non-import relay.

• The proposals for maintaining energy storage device viability put forth by the CALSEIA and SCE.

• The third-party certification or other standard that should be employed to verify the mechanism.

• Identification of any implementation risks and ways to address those risks, including through data collection and monitoring.

• The means to implement the mechanism with minimal complexity and cost for all stakeholders.

At the workshop, SCE proposed an option for monthly or daily allowable ‘tare losses’ (i.e., idle losses) if a non-physical import relay is installed based on its analysis of minimum inverter power consumption during idle operation. If a system were to exceed its allowable limits, the system would lose its VNEM credits for that month or day. These proposals include risks to delayed billing and error, according to SCE.

On March 8, 2018, each of the IOUs filed advice letters to implement D.17-12-005 in their VNEM tariffs. The IOUs indicated in their advice letters that they are working with industry stakeholders to ensure the paired energy storage device is incapable of charging from the grid, supporting a third-party certified firmware-based configuration for non-physical import relays.

On June 29, 2018, PG&E submitted an advice letter to modify their VNEM tariffs to automatically transition VNEM customers to the appropriate TOU rates pursuant to D.16-01-044. This was mostly an administrative update to make it easier for customers to comply with the NEM Successor Tariff decision and to align with the defaulting procedures of SCE and SDG&E.

On March 25, 2019, a Ruling was issued seeking comments on whether the PFM by CALSSA, MASH Coalition, and Everyday Energy filed on May 19, 2017 is still applicable, where the petitioners asserted that it is likely that many tenants of multifamily affordable housing who receive NEM solar generation credits through VNEM, in combination with mandatory TOU, will have higher bills after solar is installed than if those tenants were allowed to remain on their non-TOU rate schedule without solar. The IOUs disputed this analysis as being outdated and internally found that 99% of such customers would be better off on VNEM and TOU rates. This Ruling was issued to see if the issues motivating the PFM remain given the passage of time, updated data, and intervening events.

CALSSA, MASH Coalition, and Everyday Energy commented that D.17-12-022 exempted SOMAH participants from being defaulted to TOU service, but it does not protect customers participating in the MASH Program, who may face higher bills by moving to a TOU rate despite the application of VNEM credits to their bills. They make the case that there is no reason to exempt one subset of low-income customers but not others. The IOUs, however, found the petition to be moot given past CPUC decisions on residential default TOU rates and opt-out options as well as their analysis showing that almost all participating customers would not be adversely affected by TOU rates. The IOUs also highlighted the lack of any customer complaints since the defaulting process began and the difference in the exemption granted for SOMAH participants being that it was statutorily required.

On October 30, 2019, D.19-10-040 was issued that was largely unchanged from the PD issued on September 20, 2019 and that proposed to deny the PFM of CALSSA, MASH Coalition, and Everyday Energy to remove the imposition of mandatory TOU rates for residents of multifamily affordable housing utilizing VNEM, which the petitioners argued would have negative bill impacts. Ultimately, the PFM was denied because the petitioners did not present evidence of the negative bill impact, especially in refuting SCE’s claim that 99% of VNEM customers would see bill savings from defaulting to TOU rates. Separately, the decision proposed to modify D.18-09-044 regarding the process for receiving and addressing stakeholder input into the draft research plan for the lookback evaluation of the NEM Successor Tariff. Instead of Tier 2 advice letter process, the decision proposed to use an informal staff and letter approval process

VNEM Eligibility

On November 19, 2019, CALSSA submitted a PFM to modify PG&E’s NEM2V Tariff to include multiple parcels of land in the interpretation of “integral parcel of land undivided” for the purposes of VNEM. CALSSA explained that each of the IOUs filed different language in their advice letters to implement D.16-01-044 and to describe the properties eligible for VNEM, where SDG&E defines “contiguous parcels” while PG&E and SCE use the term “integral parcel” in reference to eligible properties. Despite nearly identical language, PG&E interprets its tariff as spanning more than one official parcel as defined by the local jurisdictional agency, but on the other hand, SCE allows projects to span more than one officially designated parcel as long as the parcels are contiguous. By having each IOU incorporate the term “contiguous parcel,” CALSSA described how this issue could be resolved. PG&E opposed the PFM because it contested CALSSA’s assertion that PG&E “revised” its interpretation of tariff language and argued that MASH and SOMAH VNEM tariffs are not directly applicable due to the low-income focus of those programs.

Self Generation Incentive Program (R.12-11-005)

Background

In 2001, the CPUC established the Self Generation Incentive Program (SGIP) in D.01-03-073 to encourage the development and commercialization of new distributed generation technologies.

In 2011, D.11-09-015 modified the primary purpose of SGIP from peak load reduction to GHG emissions reduction, and subsequently, the CPUC modified the program's incentive eligibility criteria to support technologies that achieve GHG reductions. 

In 2014, SB 861 and AB 1478 extended the SGIP for another five years through 2019. The SGIP will receive $83 million per year for a total of $415 million, funded by rates.

On June 9, 2017, an Amended Scoping Memo for R.12-11-005 was issued that set the scope for SGIP, with a focus on ongoing review, evaluation, and consideration for SGIP modifications as mandated by legislation. The proceeding is now set to close on December 15, 2018.

On June 1, 2018, the 2017 performance evaluation report was published that used data collected through interviews with representative samples of SGIP applicants, host customers, and PA staff. During the 2017 program year, the PAs received 3,663 individual applications, a significant increase from the previous year. Approximately 75% of the applications were for small residential storage projects, followed by large-scale storage projects (24.6%), and less than 1% were for generation projects.

The evaluation asked applicants and host customers to rate their satisfaction with each PA in relation to SGIP in 2017 on a five-point scale (with 1 being not satisfied and 5 being extremely satisfied). Participant ratings showed moderate satisfaction (average scores ranging from 2.8 to 3.2) in PG&E and SCE service territories and higher levels of satisfaction in SCG and CSE (3.4 to 4.1). Key takeaways about how to improve the program’s structure emerged from participant responses and include: (1) improving timeliness (e.g., lowering threshold for host customer signatures when changes are made to applications); (2) improving accessibility and transparency (e.g., SGIP portal improvements, expected timeline information); and (3) improving helpfulness (e.g., training materials, ticket system for help).

On June 22, 2018, a quarterly workshop was held to discuss the usual updates on the program’s progress, provide application best practices, present key upcoming changes, and answer stakeholder questions. Overall, the program has slowed in terms of applications and incentive claims since the Step 1 opening, but when looking at program trends since 2009, SGIP has seen a booming growth in residential emerging storage applications due to program changes in 2016 (as shown below).

Notably, the Equity Budget has not seen any applications since their opening for any of the PAs. The workshop also discussed the above process, findings, and recommendations from the GHG Working Group and Itron’s 2017 Program Evaluation Report.

On May 15, 2019, PAO submitted a motion to recategorize SGIP from quasi-legislative to ratesetting given that D.18-12-015 in the San Joaquin Valley proceeding directed the SGIP proceeding to consider the proposal to set aside $10 million in funds for energy storage pilot projects. CESA responded that the CPUC deny this motion given that this proceeding has remained a quasi-legislative proceeding despite AB 1637 implementation decisions and since the use of SGIP represents a smart use of ratepayer funds. CALSSA and GRID Alternatives also filed similar responses requesting the denial of this motion. Overall, this was a procedural matter, but it was important to keep the proceeding categorized as quasi-legislative to ensure efficiency and effectiveness in conducting outreach to CPUC Commissioners and advisors.

See CESA’s response on May 30, 2019 on PAO’s Motion to Recategorize

On June 7, 2019, a Ruling was issued on June 7 that denied PAO’s motion, agreeing with CESA and other storage providers.

On June 8, 2020, an OIR was issued to continue to evaluate and ensure the effectiveness of the SGIP in compliance with statute, with an initial focus on requirements for BTM renewable generation and heat pump water heater (HPWH) technologies and subsequently to address the GHG performance of energy storage resources. Notably, the OIR noted that it will address thermal energy storage (TES) system requirements more broadly. Presumably, with some time for the GHG rules adopted in D.19-08-001 to play out (Winter 2021), this rulemaking will review evaluation data regarding the GHG emissions performance of residential and non-residential energy storage systems and consider whether any further changes to the GHG rules. Finally, in light of SB 1369, this rulemaking will consider program revisions to consider how renewable generation incentives are available to fuel cells that use renewable fuel, including green electrolytic hydrogen.

In response, CESA advocated on the urgency of addressing the market participation barriers for TES projects. Dynamic incentive calculation methodology for LTES systems must be addressed immediately to enable their participation, while an incentive design and structure suitable for grid-interactive HPWH as thermal storage should be established in coordination with other proceedings. Furthermore, consideration of green hydrogen as a fuel for generation and storage technologies is appropriately considered in the preliminary scope. Meanwhile, CESA agreed with the need to continue to seek areas of refinement and improvement. Importantly, the GHG evaluation should account for the build-margin of storage projects as well as the avoided emissions associated with diesel generators for storage projects designed for resiliency. Furthermore, continued refinement of SGIP rules and policies should be considered to ensure alignment and effectiveness of projects in meeting the program’s resiliency objectives and priorities. A working group should also be established to address program complexity and to identify solutions to potentially streamline SGIP applications, reporting, administration, and other processes.

See CESA’s reply comments on July 7, 2020 on the Order Instituting Rulemaking

2016 Program Revisions

The Final Decision (D.16-06-055) was issued on June 23 that approved a number of pro-energy storage changes - i.e., allocating 75% of the SGIP budget for energy storage with 15% of this allocation reserved for residential storage (<=10 kW) systems. Meanwhile, generation projects will be allocated 25% of the SGIP budget, wwith a 40% minimum carve-out set for renewables from the generation budget. Overall, the SGIP now makes incentives available on a continuous, step-wise, and declining basis similar to the California Solar Initiative (CSI). The key changes are summarized below:

To protect against a quick exhaustion of funds, SGIP accelerates the decline by $0.10/Wh (instead of standard $0.05) between steps if incentives are fully subscribed within 10 calendar days and adopts a ‘pause’ mechanism between steps of no less than 20 days to allow developers to do due diligence for their projects. 

Incentive levels are also established based on duration of the energy storage project. For 0-2 hours of storage, projects are eligible for 100% of the applicable incentive level above. For hours 2-4 and hours 4-6, projects are eligible for 50% and 25% of the applicable incentive level above, respectively.

Under the new SGIP, the 40% manufacturer's cap is revoked and a 20% developer's cap has been instituted instead. These caps will be counted separately for large-scale vs. residential energy storage.

The new SGIP does retain rules for declining incentive levels for increasing MW project sizes, as well as continuing the 20% adder for California suppliers.

See CESA's comments on June 6, 2016 and reply comments on June 13, 2016 on the Proposed Decision.

On October 21, 2016, the PAs filed an Advice Letter with an attached revised SGIP Handbook, which includes new program rules and updated processes. The new SGIP program should open in Q1 2017.

Although CESA wishes to have SGIP opened as soon as possible, CESA highlighted several issues in its Protest:

• The pause period of at least 20 days should not be mandatory if a given step did not have its funds exhausted within 10 days

• A developer that has reached the 20% cap within a step should not have to wait for that step to be exhausted before moving onto the next step - i.e., that developer should be able to move to the next budget step

• The developer's cap should be updated to reflect the funds available - i.e., accounting for project attrition

• The 5 kW system sizing constraint should be a 10 kW system sizing constraint to be consistent with other programs (e.g., NEM+storage)

• System sizing limitations should be based on instantaneous customer peak demand, not customer peak demand based on a 15-minute interval

• Applications that are rejected for not being selected in the lottery should have a streamlined process for re-application

• The CPUC should think through and resolve accelerated incentive step-down scenarios

• It not clear how the application fees will be refunded if an application is not picked for an incentive level due to the lottery system

• It seems unnecessary to require the applicant to provide 12 month billing information when the IOU has access to the data

• The energy efficiency audit results should be presented at the time of incentive claim

Given the importance of getting the SGIP program right and the time it takes to implement the internal changes, CESA believes that these comments should not delay program reopening

See CESA's protest on November 10, 2016 on the SGIP PAs' Joint Advice Letter.

On November 18, 2016, CalSEIA submitted a Petition for Modification to change the amount by which the incentives available to non-residential energy storage projects supported by the Investment Tax Credit (ITC) decline in the event that a given incentive step budget is exhausted within 10 calendar days. CalSEIA is concerned that the incentive levels for both non-ITC-supported and ITC-supported projects move in tandem, causing non-residential ITC-supported projects to have incentives drop to zero under an accelerated scenario, regardless of actual subscription levels of such projects. Therefore, CalSEIA recommends that the incentive schedule for non-residential ITC-supported projects be revised to maintain a constant percentage differential between the incentives available to non-residential ITC-supported projects and non-ITC-supported projects, especially in instances where larger incentive declines is triggered. Specifically, CalSEIA proposes that non-residential ITC-supported projects be determined as 72% of the non-residential non-ITC projects.

CESA supported CalSEIA's Petition for Modification because it addressed concerns regarding how the PAs will resolve accelerated incentive step-down scenarios.

See CESA's response on December 19, 2016 on CalSEIA's Petition for Modification.

On December 9, 2016, CalSEIA submitted a second Petition for Modification to change SGIP to provide that storage devices that are not paired with renewable generators should demonstrate an average round trip efficiency of at least 66.5% over ten years to qualify for SGIP under § 379.6(b)(2), which is equivalent to a first-year round trip efficiency of 69.6%. Storage devices that are paired with renewable generators would be required to demonstrate an average roundtrip efficiency of at least 55.3% over ten years to qualify for SGIP under §379.6(b)(2), which is equivalent to a first-year roundtrip efficiency of 57.9%.

On January 9, 2017, the CPUC issued Resolution E-4824 approving the PAs’ Advice Letter with certain modifications. In sum, the CPUC accepted CESA’s comments on certain issues, such as the sizing requirement and the pause period, and not on others, such as on clarifications to the application of the developer’s cap if and when additional funds are added to the program. So in comments on the Draft Resolution, CESA recommended that the SGIP PAs adjust the developer’s cap to accommodate any new funding in steps when AB 1637 funds are added, and that the CPUC should accommodate evolving ownership structures in regards to the “developer” definition.

See CESA's comments on January 30, 2017 on the Draft Resolution.

On March 10, 2017, the PAs held a workshop to discuss new SGIP rules and procedures, new database and application functionality, and next steps in SGIP including potential storage operation rules and budget scenarios. Energy Solutions also provided a demo of their SGIP portal. Importantly, the PAs revealed that the program will have a 'soft opening' where applicants can log into the portal and begin working on application materials, and open the program for application submissions and reservation requests on May 1. The program will open with approximately $40 million in already-authorized funds in Step 1, in addition to funds from cancelled projects (rumored to be in the $30-$40 million range) and application fee forfeitures.

On April 15, 2019, a Ruling was issued seeking comment on implementation of SB 700, which authorized the CPUC to extend annual collections for the program for five additional years, from December 31, 2019 to December 31, 2024, and extends administration of the program for five additional years, from January 1, 2021 to January 1, 2026. The Ruling sought feedback and responses on several program design areas. CESA recommended higher incentive rates for non-residential storage projects to help address economic barriers and that the CPUC maintain step structure with smaller step-downs and include ratchet-up structure if a certain amount of funds available is not subscribed by a set period of time. CESA recommended an adjustment upward of incentive rates for duration of energy storage projects to support resiliency, long-duration, and thermal storage projects: 100% for 0-4 hours, 50% for 4-6 hours, 25% for 6-8 hours, and 0% for >8 hours. Finally, CESA recommended that the CPUC remove incentive rate step-down by project size and remove project size limit given sufficiency of funds and other controls in place (e.g., interconnection, NEM eligibility).

See CESA’s comments on May 30, 2019 and reply comments on July 12, 2019 on the Ruling

Lottery Mechanism

On July 18, 2016, the SGIP Program Administrators (PAs) hosted a workshop on the SGIP lottery system that would need to be developed to manage project selection for applications received on the same day. The workshop solicited stakeholder feedback on the mechanics, scoring criteria, administration, gaming, and penalties of the lottery system. Key questions related to how to score ‘lottery priority’ criteria, which, per D.16-06-055, could be granted to renewable-plus-energy storage projects and energy storage projects located in the West LA Basin and LADWP areas. Some details apparently remain to be clarified, such as the level of charging required from renewable generators to receive the lottery priority and how this level would be verified. The next steps in the lottery mechanism development are for the Program Administrators (PAs) to file a Tier 2 Advice Letter seeking approval of their proposals by October 21.

On April 3, 2017, Advanced Microgrid Solutions, Green Charge Networks, and Stem (collectively known as the "Joint Storage Parties") filed three Motions communicating their concern about the integrity of SGIP and asserted the need to investigate the existing and potential additional lottery priority criteria. Specifically, the Joint Storage Parties highlighted their concern regarding the surge of interest from solar-plus-storage developers combined with the SGIP Program Administrators (PAs) cursory review of charging from the renewables and the lack of standardized metering options to validate charging from the renewables, which together lead to the high probability of significant project failures. To ensure that standalone storage projects are not prevented from access Step 2 incentive rates, the Joint Parties propose:

• A CPUC staff investigation into developer registrations

• Additional priority designations, such as grid-support criteria, for consideration

• Shortened time for responses to the two concurrently filed motions (five-day response period instead of the normal 15 days)

The Joint Storage Parties hope to address their cited concerns without program opening delay. Note that the Administrative Law Judge (ALJ) may shorten the comments period for good cause.

On June 2, 2017, a Ruling was issued that denied these Motions on the grounds that the CPUC does not see evidence that standalone storage projects have been excluded from Step 1 funds.

Energy Storage Installation Eligible Licenses

On July 18, 2017, CSE received verification from the Contractors State License Board (CSLB) that the C-46 Solar Classification is an appropriate license classification to install an energy storage system as part of a solar installation. CSE therefore proposes to amend the SGIP Handbook to allow for C-46 license holders to perform such installations. These modifications would not affect the installation of standalone storage systems, which must be installed by a contractor with an active A, B, or C-10 license. 

SGIP Operational Requirements & Application Process

Background

D.16-06-055 amended the Performance Based Incentive (PBI), the 50% portion of the SGIP incentive based on performance for systems larger than 30 kW, to require energy storage discharge for only one hour per day (annual minimum of 260 hours of dispatch). Under old program rules, the PBI is pegged to a formula that requires dispatch of an energy storage system for at least two hours per day (annual minimum of 520 hours of dispatch). The new rules, on the other hand, ensure that energy storage is not uneconomically dispatched to ensure receiving the full SGIP incentive, and reduce complexity for program administration of two sets of rules.

Application Process

On September 17, 2019, the Joint PAs submitted two Petitions for Modification (PFMs) to streamline the SGIP application requirements by doing the following:

• Removing the application fee for residential projects: This fee was instituted at 1% and later raised to 5% to ensure that submitted projects were viable and committed to meeting program milestones. While not proposing to remove the fee for non-residential projects, the PAs justified eliminating the fee for residential projects because of the volume of applications (i.e., thousands of checks to deposit) that lead to administrative burden. The PAs also noted the lower attrition rate for residential projects.

• Removing the requirement to provide building permits issued by an IOU for energy storage projects: The PAs highlighted how building permit sign-offs are already part of the Rule 21 interconnection process for obtaining permission to operate (PTO), so removing this requirement is reasonable, though it is still needed for non-IOU projects (e.g., LADWP projects).

• Removing the requirement to submit a hard copy of the Energy Efficiency Audit (EEA): Since the PAs are no longer reviewing and enforcing specific EEA findings under a two-year requirement, and the EEA submission does not guarantee customer action, the PAs propose instead that the host customer be required to attest on the legally binding and executed Reservation Request Form (RRF) that they received and reviewed the findings of an EEA.

CESA supported the proposed common-sense changes that will make life easier for SGIP applicants by streamlining the application process while adhering to the program's goals.

See CESA’s responses on October 16, 2019 to the Petition for Modification

On October 31, 2019, the PAs decided to withdraw their streamlining-focused PFM because the PAs were concerned that it is premature to eliminate any current AHJ inspection documentation without further evaluation of and coordination with these additional AHJ documentation obligations identified by the CPUC. The PAs also expressed some concern with forgoing AHJ inspection documentation in other POU territories if parties are able to demonstrate interconnection procedures that require a final building permit since the PAs have not had an opportunity to assess the differing interconnection protocols and enforcement of the 46 POUs across the state.

On January 27, 2020, D.20-01-021 was issued that directed the PAs to adhere to a 45- to 60-day timeline for fully processing incentive applications to support streamlining. Meanwhile, the decision declined to carve-out dollars to local partners, instead recommending that the PAs develop a “customized” marketing, education, and outreach (ME&O) plan.

On February 18, 2020, D.20-02-002 was issued that would eliminate application fees for residential energy storage projects, effective February 14, 2020, and allow host customers to submit an attestation that they have had an energy efficiency audit performed and reviewed its findings rather than submit a paper copy of the audit. The modifications were intended to reduce application processing time and transaction costs for claiming SGIP funds. Compared to the PD, the decision was revised in response to comments from CALSSA to direct the PAs to submit an implementation advice letter by February 14, 2020 reflecting the decision’s changes along with the other implementation details related to non-residential aspects of the Equity Resiliency Decision (D.19-09-027). The decision would also close this proceeding. As directed, the PAs submitted an implementation advice letter that reflected the changes in D.20-02-002. Due to the relatively straightforward nature of implementation, CESA found no issue with the advice letter.

On April 15, 2020, PAs submitted a joint advice letter that proposed revisions to the SGIP Handbook to address the remaining orders in the SB 700 decision (D.20-01-021), including funding collections and allocations for the different budget categories and for PA administrative expenses. Notably, to comply with the application processing timelines (i.e., 10 days from submittal to review, 45-60 days to fully process applications), the PAs reported on additional staffing and IT resources. In addition, the PAs proposed a statewide equipment vetting process that results in a pre-approved equipment list. All equipment must be vetted by the technical consultant (AESC) and receive approval prior to the Reservation Request Form (RRF). All projects that fail technical review will be subject to the normal 15- to 30-day suspension process.

CESA discussed how several of the implementation details are either be non-compliant with D.20-01-021 or lacking in sufficient clarity. Specifically, the use of pre-approved storage equipment lists will delay project applications, is not required by the D.20-01-021, and should not be used.

See CESA’s protest on May 5, 2020 on the PA Advice Letter

On June 5, 2020, the PAs submitted a supplemental advice letter that made a number of changes in response to parties’ protests. While the PAs voiced their continued recommendation to ensure equipment be pre-approved by the SGIP technical consultant prior to a RRF submission, they instead adjusted their approach to allow projects using equipment that has not been pre-approved to submit applications and create a new status within the RRF review for vetting new equipment that would not count against a PA’s target review timeline. The PAs will use their discretion and only suspend developers who do not act in good faith in their requests. These changes were subsequently approved several weeks later.

Field Inspection Protocol & Requirements

On November 14, 2016, the SGIP PAs held a workshop to discuss operational requirements and deployment, inspection sampling, and an energy storage inspection protocol. The PAs introduced their Field Inspection Sampling Protocol at the workshop, which will be managed by PA, apply to each developer, and be separate for residential and non-residential projects.

On April 27, 2017, the PAs jointly filed an advice letter to implement a Field Inspection Sampling Protocol and revise the Energy Storage Inspection Protocol. The proposed sampling protocol applies to developers with multiple SGIP reservations and will be managed separately by each PA and by residential and non-residential projects. The protocol is as follows:

• The first three projects using the same model for each developer in both the residential and non-residential customer category will be inspected

• Once three inspections from a single developer have been successfully completed with no failures or suspensions, one in five projects may be randomly selected by the PA for inspection.

• At the PA’s discretion, one in ten projects may be randomly selected for inspection after six total successful inspections

• New equipment models introduced by a developer during the inspection sampling cycle will be inspected for at least three applications and will resume the one in five sampling rate if the inspections are successful

• Any failed inspections resulting in a need to physically re-inspect the project will result in a reset of the inspection sampling (i.e., starting back at the one in five sampling rate)

Suspensions occur when the equipment is operating normally but another requirement of the inspection process is not satisfied – e.g., incomplete discharge dataset, equipment not matching reservation documentation, etc. – and can be resolved through revised documentation. Failures, meanwhile, occur when a project does not fulfill program rules – e.g., equipment is not operating properly – and therefore requires re-inspection.

The revised inspection protocol applies to all developers and is as follows:

• Verification that all necessary equipment information is easily visible from the outside or on the interior of the system

• Verification that the energy storage system is configured to operate in parallel with the grid, load shave, and serve on-site load

• Demonstration of energy storage system performance under normal operation through the review of one weeks’ worth of data

• While on-site during the inspection, the inspector may be required to witness a discharge demonstration of the system – performed on-site or remotely by the developer, system owner, or host customer

Independent of the field inspection visit, the project must also submit either: (1) an independent continuous discharge test; or a factory continuous discharge test report by the manufacturer or system integrator accompanied by a 30-minute field test. The results of the continuous field or factory discharge test over the specified discharge duration must be within +/- 5% of the SGIP incentivized capacity in the incentive claim documentation. Projects yielding test results outside of the +/-5% threshold are subject to capacity and incentive adjustments according to the test results, and may be subject to additional eligibility requirements before final approval.

CESA responded with a focus on reducing the administrative burden of these inspection protocols with a 1-in-100 sampling rate (instead of the proposed 1-in-10 sampling rate) in the third step of the Field Inspection Sampling Protocol, and ensuring that discharge requirements do not violate intended operations or interconnection agreements.

See CESA's response on May 17, 2017 on the Joint PA Advice Letter. 

The Joint PAs replied to Responses from CESA, CALSEIA, and Tesla as follows:

• The requested 1-in-100 sampling rate is unreasonable because of the influx of new SGIP developers and the precedent set by the 1-in-12 sampling rate applied in the California Solar Initiative (CSI).

• CALSEIA’s recommendation to automatically reduce the sampling rate after successful inspections should be rejected since administrative flexibility and discretion of the PAs should be maintained.

• The PAs concur with CALSEIA and Tesla that new model numbers should necessitate an inspection sampling rate reset, but disagrees with their recommendation to limit “new equipment models” to battery packs as the other equipment (e.g., to include inverters and other ancillary equipment) affects system output and operations.

• The PAs clarify that the 1-5 minute interval requirement is only needed for the discharge testing protocol in order to ensure sufficient data points is collected over the short period of time, and they note that most discharge data submitted to the program has been in 1-5 minute intervals.

• The PAs affirm that the 30-minute discharge test is not intended or required to demonstrate output at the full rated capacity, nor is it the intention of the protocol to violate the customer’s non-export interconnection agreement.

On April 11, 2018, the PAs filed a joint advice letter to modify the current field inspection sampling and discharge testing protocol, which was adopted in August 2017 to streamline the verification for SGIP-funded energy storage projects that ensures systems perform as expected and agreed-upon. Currently, projects selected for an inspection may choose one of two options:

• Provide one week’s worth of operational data and a field test measuring energy storage system output over the discharge duration specified on the application; or

• Provide one week’s worth of operational data, a factory test measuring energy storage system output over the discharge duration specified on the application, and a 30-minute continuous discharge field test from the system at the project site

In the joint advice letter, the PAs observed that the 30-minute discharge field test was duplicative and unnecessary and thus proposed to remove this test from the protocol. Instead, the PAs proposed that the one week’s worth of operational data contain 15-minute discharge interval data, among other things. For similar reasons, the PAs proposed that the requirement to supply discharge data in less than 1-minute and no more than 5-minute intervals was no longer necessary. Finally, the PAs also proposed removing the requirement to supply load identification and average cell temperature or ambient temperature information at the time of the tests, finding this unnecessary to complete this test and only serving to delay incentive payment despite no temperature-related requirements for discharge.

On March 11, 2019, a joint advice letter from the SGIP PAs was submitted that proposed 10 modifications to the SGIP Handbook. First, the SGIP PAs made modifications to utilize a public SGIP Equipment List to support SGIP applicants in identifying equipment that meets the program’s technical requirements – a list that was previously internally maintained by the PAs. For equipment that is already reviewed by the SGIP Technical Working Group and populated on the SGIP website, applicants would no longer need to upload manufacturer specification of equipment. Specifically, manufacturers would be required to release the following information:

• Manufacturer name

• Model ID

• Storage capacity (kWh AC or DC)

• Rated capacity (kW)

• Discharge duration

• Inverter continuous power output

• CEC inverter efficiency

There were a number of other modifications proposed in the advice letter:

• Virtual inspection: The SGIP PAs propose to allow virtual inspections of residential projects in lieu of on-site field inspections to confirm that a project is installed according to program requirements. The SGIP PAs believe that these project types are typically less complex and have less variability as compared to larger non-residential systems.

• Copy of the check: The SGIP PAs propose to remove the requirement for a copy of the check submitted with the SGIP application, which was found to be too burdensome to applicants and PAs.

• Residential customer notification opt-out: The SGIP PAs propose to allow residential customers to opt out of non-critical email communications, especially as the applicant, not the host customer, normally resolves issues related to missing information or needed clarifications.

• Consolidation of project cost forms: The SGIP PAs propose to consolidate the project cost affidavit and the project cost breakdown, which are intended to substantiate total eligible project costs, into the incentive claim form. This is intended to reduce paperwork and streamline the administrative process.

• CSE customer information access: The SGIP PAs propose to remove the requirement for third-party authorization to receive customer information form for systems less than or equal to 10 kW, which is an issue for CSE that does not have access to the SDG&E utility customer account information without a signed authorization submitted to SDG&E. By removing this requirement, CSE will be better able to serve its PA role.

• Final monitoring scheme: The SGIP PAs propose to require a final monitoring scheme for all projects since this is a key document in supporting the engineering review process as it minimizes the need for repeat communications. A detailed single-line diagram is required to be submitted at the incentive claim stage for projects that are equal to or greater than 30 kW and/or for projects paired with and charging 75% from an on-site renewable generator.

• Application fee: The SGIP PAs propose to extend the application fee refundable period for three-step projects to the confirmed reservation step, consistent with the process for two-step applications. Currently, for three-step applications, application fees are non-refundable if the application is cancelled after a conditional reservation is issued. As a result, the change would provide more time and flexibility for applications to find and secure alternative project funding sources after the conditional reservation is issued.

• Performance data provider (PDP) audits: The SGIP PAs added language to clarify that they can conduct PDP audits not only on a random basis (current) but also if they have a reasonable basis to question the accuracy of data submissions.

In general, CESA supported most of these proposed minor modifications. They were all reasonable and should make life easier for CESA members involved in the SGIP application process. CESA was supportive of all these ‘tweaks’ but offered comment on how to coordinate (and potentially consolidate in the future) the SGIP Equipment List with the CEC’s Storage Equipment List, which is currently in the process of being developed.

See CESA’s response on April 1, 2019 on the to the Joint PA Advice Letter

The CPUC issued a suspension notice on April 3 for up to 120 days to allow for more staff time to review.

Marketing, Education, & Outreach (ME&O)

On January 14, 2020, a quarterly workshop was held to discuss implementation updates on the Equity Budget as well as the Equity Resiliency Budget changes for small residential customers. The workshop also covered the PAs’ preliminary ME&O Plan, including key messages to reach customers with critical resiliency needs. Stakeholders recommended that the PAs collaborate with community-based organizations (CBOs) as a primary channel for communication; remove barriers to adoption; provide educational materials to aid program participants in understanding and verifying eligibility for the Equity Resiliency Budget; integrate opportunities with key partner programs; and develop key messages to educate customers with medical disabilities helping to guide them through the process to program adoption.

On February 20, 2020, PG&E submitted its territory-specific ME&O Plan for residential equity resiliency projects. Marin Clean Energy (MCE), Sonoma Clean Power (SCP), and GRID Alternatives protested the advice letter for failing to collaborate with CCAs and low-income solar PAs and to include budget line items for these third-party partners ($55,000-$105,000 per year). MCE and SCP presented their own proposals that intend to leverage existing CCA-specific and other programs and utilize community-based communication channels, while GRID Alternatives found issue with the omission of Equity Budget customers in primary and/or secondary target market.

On May 5, 2020, SCE submitted an advice letter on how it will monitor participation rates and customer feedback to iterate on their ME&O strategy for the Equity Resiliency Budget. CBOs will play a key role in the SGIP program by serving as the direct touchpoint for local communities, and each selected CBO will be awarded an amount of up to $5,000 to support these efforts.

On May 22, 2020, CSE submitted an advice letter implementing their ME&O strategy that recognized the importance of working closely with CBOs and low-income solar PAs to effectively engage with hard-to-reach communities. As a result, CSE proposed to dedicate 28% of overall ME&O spending, and 35% of annual ME&O spending through 2023, to funding these partnerships. This plan also proposed to support developers in identifying customers that are eligible for the Equity and Equity Resiliency Budgets while protecting customers’ personal information, as well as equip them with standardized educational material and marketing collateral that can help lend credibility to what may at first appear to be “too good to be true.” CSE will provide content toolkits and educational collateral to developers to both aid in the customer acquisition process as well as lend credibility to a developer’s claim of a fully incentivized energy storage system.

On July 21, 2020, Resolution E-5086 was issued that approved PG&E’s SGIP Residential Equity Resiliency Marketing Plan with a $765,000 budget but sternly directed that PG&E open up lines of communication immediately with the CCAs and low-income solar program administrators. Despite the CCAs’ request for a portion of PG&E’s ME&O budget, this request was denied because the directing decision only required collaboration and not budget carve-outs for partners. A $300 Customer Recruitment Incentive on a per-customer basis will be available to CBOs, including CCAs, who help targeted residential and non-residential customers who successfully submit an SGIP application. Of the total budget, $300,000 is allocated for these incentives, where $50,000 of this allocation available to CBOs with 20 or fewer staff. Though not being required to re-file their ME&O Plan due to the lack of collaboration, PG&E must engage with these entities on development of the toolkit and make the final version publicly available for download on its website within 30 days of adoption of this resolution. In line with GRID Alternatives’ recommendation, PG&E should prioritize low-income, medically vulnerable customers first as medical baseline customers are likely to be particularly vulnerable and those who are low-income face the greatest need for assistance when adopting energy storage. A revised ME&O Plan will be required by March 15, 2021.

SGIP Developer Cap

Background

D.16-06-055 established a 20% limit on funds that any one developer may receive through the SGIP. However, SGIP does not currently define what or who is a developer. In order to create a clear and robust definition, as well as prevent potential gaming, the SGIP Program Administrators (PAs) solicited industry feedback on defining “developer” through an online questionnaire on August 17, 2016.

On August 25, 2017, Draft Resolution E-4887 was issued that revised the developer definition to account for the complexities of project finance and development structures. CESA voiced support for the intent of the developer’s cap but expresses caution in how we tune the developer’s cap. Specifically, CESA noted that:

• The activities and approach for determining a developer as listed in the Draft Resolution need to be re-considered to increase precision in differentiating a developer role from other “project-support” roles.

• The determination of “substantial amount” of project development needs to be specified to reduce subjectivity in its interpretation.

• The new developer cap should limit inherently retroactive elements.

• The new definition should be applied on a “going-forward” basis.

• The new developer definition should be applied consistently across PAs.

• The CPUC/PAs should have authority to investigate potential infractions.

See CESA's comments on September 18, 2017 on the Draft Resolution.

On October 12, 2017, Resolution E-4887 was approved that adopted a modified definition of “developer” to include an entity that does not hold the contract with the customer for installation of a storage system but still handles a substantial amount of the project’s development activities. According to the Resolution, this change is being driven by the fact that there are some projects where multiple developers play a role in developing a project, while only the developer holding the contract for purchase and installation of the energy storage system is counted against the developer’s cap. The CPUC indicated its intention to prevent gaming and the subversion of program rules. The developer that is determined to handle a “substantial” amount of the project’s development activities will be determined be the designated developer for any given project. Like the draft, the Resolution gives discretion to the PAs to make the determination of “substantial”. The Resolution also implements an expanded Developer Eligibility Application that seeks information on all development activities handled by a developer – information that is important to determining what is “substantial”. The Resolution proposes the following “development activities” that will feed into this calculation for “substantial”:

• Approaching or communicating with the target customer about the potential project and learning about its needs and energy profile (#1)

• Developing the specifications for a system based on the customer’s needs and interests (#2)

• Soliciting bids from multiple manufacturers for the specified system (#3)

• Gaining the customer’s commitment to purchase or lease the specified system (#4)

• Purchasing the specified system from the manufacturer to fulfill the obligation to provide a system to the customer (#5)

• Securing permits and interconnection permission for the system on behalf of the customer (#6-7)

• Submitting SGIP applications, liaising with SGIP PAs on incentive reservations and data reporting requirements, and submitting project data and reports (#8-10)

• Physically constructing and installing the system at the customer’s premises (#12-13)

Notably, in contrast to the Draft Resolution, the project development criteria eliminated two criteria related to operating and maintaining the system and the list of four project development activities that would default an entity to developer status if it handled all four of those activities. In addition, in contrast to the Draft Resolution, the retroactive reassignment of developers to a project was more clearly and narrowly defined, which set the time between conditional reservation and confirmed reservation as the window in which the PAs have discretion to adjust the designated developer for a project. A number of other changes and clarifications were made in the Resolution:

• Homeowners, not just corporate entities, may self-develop their projects.

• Corporate developers must be registered and in good standing with the Secretary of State of California.

• Relationships between developers in co-developed projects must be disclosed, including commercial or financial relationships

• “Same majority ownership” in the developer definition no longer just applies to traditional parent-child relationships of corporate entities, but also to other ownership interests (e.g., subsidiaries of a single parent corporation, private equity firm, investment bank, or group of individual shareholders)

• The CPUC has the authority to independently investigate infractions and issue penalties

With these changes, the results are mixed. On the one hand, there is a defined window for retroactive adjustments to the definition of developer, which should reduce some of the uncertainty for financing SGIP projects. In addition, the operations and maintenance of energy storage systems was appropriately removed from the list of project development activities. On the other hand, there is still lack of clarity on how the PAs will determine “substantial”, even within any one given project development activity, which may be shared by multiple entities. With PA discretion to make this determination, there may be issues with differences in how the PAs will apply the “substantial” definition. The other potential issue is that the process for defaulting entities as developers based on a shortlist of criteria represented a potential way to streamline this validation process, but it was not included in the approved Resolution.

The PAs have updated the Developer Eligibility Application form to be used for Step 3 and later steps pursuant to Resolution E-4887 and have publicized the revised form. Each SGIP Developer will be required to resubmit their Developer Eligibility Applications prior to submitting Step 3 applications using the newest Developer Eligibility Application.

On December 15, 2017, a workshop facilitated by the PAs was held to discuss the implementation of several key changes, including the new developer application. Every week, the PAs noted that they plan to meet to address any applications that require an assessment on the subjectivity of the “substantial” definition.

Key Revisions

On January 27, 2020, D.20-01-021 was issued that directed the PAs to submit a Tier 2 advice letter suspending or modifying the developer cap if the incentive step has been open at least 12 months, at least two entities have reached their cap, and there is otherwise low participation in the incentive step, leaving some discretion to the PA and CPUC staff, especially with a consideration of overall resiliency needs. This was in part in response to CESA’s recommendation that the developer cap should be lifted after a certain period of time in a given step budget category to support utilization of these funds.

See CESA’s comments on January 3, 2019 on the Proposed Decision

SGIP Equity Budget

Background

On June 2, 2017, a Ruling was issued that built off D.17-04-017, which expressed the CPUC’s intent to have a portion of the AB 1637 funds reserved for projects located in disadvantaged communities. This Ruling proposed to implement a 20% carve-out of the statewide Steps 3-5 budgets for ‘disadvantaged communities’, which are defined as communities in any census tract that ranks in the statewide top 25% most affected census tracts in the most recently adopted version of CalEnviroScreen. Each PA will establish this carve-out in proportion to the share of qualifying disadvantaged communities in their service territory (e.g., if 55% of statewide disadvantaged communities are in SCE’s territory, then SCE would need to allocate 55% of its step budget to disadvantaged communities). The Ruling indicated its intention to implement this new program design before Step 3 opens. If these changes cannot be implemented by that time ( due to potential IT or regulatory delays), the opening of Step 3 will be postponed until this policy can be implemented. No changes are made to the design of the developer cap.

The Ruling also proposed to establish ‘grid services’ eligibility requirements for SGIP-funded projects:

• All non-residential customers seeking incentives must either: (1) take service on the utility’s critical peak pricing (CPP) rate; or (2) participate as an aggregated DR or DER product that is bid into the CAISO’s wholesale markets

• All residential customers seeking incentives must either: (1) take service on a CPP rate; (2) take service on a TOU rate; or (3) participate as an aggregated DR or DER product that is bid into the CAISO’s wholesale markets

• CPUC Resolution E-4717 would now be voided and no longer allow residential customers to avoid TOU or CPP rates if they discharge during peak periods

CESA reiterated its support for the three program goals (as well as the broader statewide disadvantaged community goal), and also offered recommendations and revisions to the DAC carve-out. For example, clear goals and target customer segments of this carve-out should be identified to ensure the desired goals for DACs are smartly met. In addition, independent budget category for DACs and a de-coupling of the DAC budget from other budget categories should be considered. CESA also discussed how the grid services eligibility requirement is too restrictive. The grid services eligibility requirement would cut off significant segments of the energy storage market and lacks clarity on impacts to SGIP projects due to regulatory and policy changes. Furthermore, CESA argued that operational requirements are already in place to ensure cycling of energy storage systems and thus focus should instead be placed on developing rate designs that align with grid needs and provide environmental benefit.

See CESA's comments on June 22, 2017 and reply comments on June 27, 2017 on the Ruling.

On August 25, 2017, a PD was issued establishing the Equity Budget in SGIP for Steps 3-5. In response, CESA recommended that the SGIP not overly limit the types of energy storage projects that can apply for the new Equity Budget, while also striving to ensure that the DAC and low-income objectives are met. CESA's comments are summarized as follows:

• Eligibility criteria for commercial customers should be expanded to include all commercial customers located in the eligible DAC and low-income census tracts and communities.

• The Equity Budget should only reserve 20% of SGIP funds from Steps 3-5, as broadly supported by parties in the June 2, 2017 Ruling.

• Existing rules for the small residential and large energy storage budget categories should apply to the Equity Budget as well.

• The threshold criteria for setting a higher Equity Budget incentive rate should be adjusted to avoid one reservation from setting a more market-responsive incentive rate.

• The Equity Budget should be decoupled from the other budget categories to ensure continued market transformation.

• The PAs should be directed to provide zip codes of qualifying disadvantaged and low-income locations.

• The CPUC should not adopt any new grid services eligibility requirements.

CESA responded to some of the recommendations by the IOUs to consider grid services eligibility requirements and to approve a 90-day implementation period for IT changes prior to Step 3 opening.

See CESA's comments on September 14, 2017 and reply comments on September 19, 2017 on the Proposed Decision.

On October 12, 2017, D.17-10-004 was issued that set aside 25% of the funds for the SGIP (i.e., proportionally from both small residential and large budget categories) into an “Equity Budget” starting with Step 3. The CPUC maintained the 25% allocation to the Equity Budget given that nearly 20% of such incentives are already being used in disadvantaged communities. As compared to the PD, D.17-10-004 includes a new carve-out within the Equity Budget. For incentive Step 3 and subsequent incentive Steps, 10% of the Equity Budget is reserved for single-family and multi-family low-income housing regardless of the size of the energy storage project. The decision reasons that the low-income residential sector may not have an opportunity to benefit from the Equity Budget otherwise. The disadvantaged community (DAC) and “low-income community” definition for eligibility is maintained in D.17-10-004 as it was for the PD, which had expanded eligibility to certain non-residential and all residential customers in low-income communities in response to CESA’s comments. D.17-10-004 defines “low-income community” such that it is the same as §39713(d)(2) of the Health & Safety Code and aligned with the framework for allocating funds from the GHG Reduction Fund. On the residential side, D.17-10-004 relied on the definition for the AB 693 Program. As compared to the PD, D.17-10-004 also simplified the definition of “small business” from the California Department of General Services’ (DGS) more expansive criteria to a simple criterion based on annual gross revenues.

Given the expanded eligibility criteria, D.17-10-004 decided against allocating the set-aside in proportion to each PA’s share of DAC communities out of the total statewide, as in the original Ruling, but instead directed each PA to equally allocate 25% of its total energy storage budget, drawing proportionally from the Steps 3-5 budgets of the small residential and large categories. This is simpler and easier to administer, according to the decision. The 25% allocation from the Steps 3-5 budgets is also an increase from the 20% allocation proposed in the Ruling, which is due to the set-aside being from the energy storage side only, not both the energy storage and generation side. Importantly, the decision declines to set higher incentive levels for the Equity Budget at this time due to insufficient evidence, but it sets a systematic streamlined process for adjusting up the incentive level. The PD proposed to consider higher incentive levels if four months passes with no reservation from this category. CESA had concerns with this approach expressed in comments. The decision has thus revised its process such that if a PA does not confirm any reservations within the Equity Budget during any rolling three-month period, while five or more energy storage projects not eligible for the Equity Budget secure confirmed reservations in the same time period, this will constitute a triggering event. This process and analysis applies separately to small residential and large-scale energy storage systems. If triggered, the PA will increase the incentive amount by $0.05/Wh (but only up to a maximum incentive rate of $0.50/Wh). Within 30 days of the triggering event, the PA must submit a Tier 1 advice letter to inform Energy Division about the triggering event. This represents some improvement to the PD that leverages the existing incentive rate schedule to be responsive to the market but it may still be subject to outlier effects.

There are a number of other determinations made regarding the Equity Budget:

• Eligibility for the new budget category will be structured such that any sized energy storage project may apply for this category.

• A separate developer’s cap will apply to the Equity Budget, similar to how a separate developer’s cap applies to the small residential and large budget categories respectively.

• Incentive levels for the Equity Budget and general budget will operate independently of one another.

• Projects eligible for the Equity Budget may apply for the general budget funds within that same incentive step if funds are available.

• Incentive levels will not be adjusted due to insufficient evidence at present, but may be considered for a higher incentive level if four months passes with no reservation from this category.

Equity Budget Revisions

On April 15, 2019, a Ruling was issued seeking comment on implementation of SB 700, which authorized the CPUC to extend annual collections for the program for five additional years, from December 31, 2019 to December 31, 2024, and extends administration of the program for five additional years, from January 1, 2021 to January 1, 2026. The Ruling sought feedback and responses on several program design areas.

CESA supported key program modifications but added that  the CPUC should view SGIP as a market transformation and technology deployment program and strive to avoid making program rules and processes overly complex, while still being a sophisticated program that effectively achieves its goals. CESA provided industry insight into the low participation levels seen in SGIP for Equity customers and recommended an increase in incentive rates to $0.75/Wh at minimum for Equity projects (based on SCE's AB 2868 BTM Program proposal). Adders could also be created within DAC-SASH and SOMAH programs that use SGIP funds but would take advantage of DAC-SASH and SOMAH ME&O activities. Furthermore, CESA supported the use of SGIP funds to direct SGIP projects for resiliency purposes by establishing a 20% Resiliency Adder to the incentive rate for eligible customers in High-Fire Risk zones, with demonstrated capability to do resiliency, and with certain exemptions to SGIP operational requirements, and generally supported the 10% set-aside of SGIP funds for use in the SJV pilots as a prudent use of ratepayer funds.

A range of ideas around resiliency, electric water heaters, and Equity budget were also proposed. In response, CESA commented that energy storage represents a better resilience solution than a traditional diesel generator and added that electric water heaters should be incented to support market transformation, decarbonization, and disadvantaged community goals.

See CESA’s comments on May 30, 2019 and reply comments on July 12, 2019 on the Ruling

On August, 9, 2019, a PD was issued that focused on modifications to jump-start the Equity Budget, which has seen virtually no participation. To address these barriers, the PD proposed to modify Equity Budget eligibility rules to become more broadly available, to increase the incentive rate to address how poor economics is the main barrier, and to take advantage of synergies with low-income solar programs, among other changes. No decisions were made on funding collections and allocations for 2020-2024 as authorized by SB 700, with the proposed changes mostly involving a shifting and carve-outs using already authorized funds collected through 2019, though we should expect some backlash from companies interested in preserving Generation Budget funds (e.g., fuel cell companies).

CESA generally supported the increased Equity incentive rate, the new Equity Resiliency Budget category along with a higher Equity Resiliency incentive rate, and the modifications to the incentive rate step-down structure based on energy duration but believed that these specific changes should be modified to varying degrees.  The CPUC was well-intentioned in proposing these changes but CESA recommended that the Equity and Equity Resiliency incentive rates should be set higher to initially cover 100% of eligible project costs, longer durations should be incentivized at higher rates given some of the misunderstandings of long-duration storage technologies, and cycling and GHG requirement implications should be reconsidered for the resiliency use case.  Furthermore, while the near-term focus of this PD is focused on Equity Budget changes, CESA recommended that the Commission also consider changes to General Budget projects that support resiliency applications as well as longer-duration technologies.

Many other parties submitted comments on the PD with most parties expressing support for the changes to the Equity Budget and the establishment of the Equity Resiliency Budget; however, some parties expressed concern with the viability of energy storage to provide resiliency in certain cases while others protested the transfer of funds from the Generation Budget to the Equity Resiliency Budget. In response, CESA supported higher Equity incentive rates and broader eligibility for the Equity Resiliency Budget but also rebutted parties’ comments opposing fund transfer from the Generation Budget to the Equity Resiliency Budget, HPWH eligibility, and additional processes to validate islanding. Finally, CESA recommended that disclosure language around energy storage capabilities should be provided to customers needing resiliency for critical medical equipment.

See CESA’s comments on August 29, 2019 and reply comments on September 3, 2019 on the Proposed Decision

On September 18, 2019, D.19-09-027 was issued that modified Equity Budget eligibility to now include:

• California Indian Lands (including at least one owner who is tribe/tribal member in multi-owner lands)

• Any facility owned or operated by a public agency that provides services to community members, who are at least 50% of census tracts served from DACs (applicant burden of proof)

• Customers eligible for MASH, SASH, DAC-SASH, or SOMAH Programs

To make Equity Budget incentives more widely accessible, the decision also made the following changes, though it did not alter the cycling or GHG requirements for Equity projects until further information is available: 

• Direct PAs to update system sizing requirements for multifamily housing based on property’s historical electrical usage, leveraging SOMAH processes to determine energy usage

• Eliminate reduction of SGIP incentive if non-SGIP incentives used (only for Equity Budget) but must not exceed 100% of project costs

• Direct PAs to develop a customized Equity Budget ME&O Plan to co-promote SGIP along with SASH, DAC-SASH, and SOMAH incentives, including workforce training option

• Eliminate the 20% developer cap only for the Equity Budget

• De-links the opening of Equity Budgets based on General Budget progress such that PG&E’s Equity Budget is opened immediately

• Adjust incentive step-downs based on duration to be 100% for hours 2-4 and 50% for hours 4-6 to support Equity and Equity Resiliency customer needs

Importantly, the base incentive rate for Equity projects was increased to $0.85/Wh, which the decision equated to covering close to 83% of total eligible costs, up from 50% under previous rates, and the incentive rate step-up mechanism was eliminated to prevent waiting by developers. For the Equity budget only, the decision also adjusted incentive step-downs based on duration to be 100% for hours 2-4 and 50% for hours 4-6 to support Equity and Equity Resiliency customer needs. No changes were made to funding allocations of the Equity Budget.

Second, a new $100-million Equity Resiliency Budget category with a higher base incentive rate ($1.00/Wh) was established to target customers who have least ability to fund storage system and critical facilities who serve Equity-eligible customers. Funding for the Equity Resiliency Budget will come from the accumulated unused generation budget. Eligible storage systems must be inspected and approved to be able to island by local authorities having jurisdiction (AHJs) and SGIP applicants must submit attestations to their ability to provide battery service during outages. The decision warned that developers should not increase price of system because of these higher incentives and maintained that operational and GHG requirements would still apply.

Finally, two Equity Budget set-asides were established using funds transferred from the accumulated unused non-residential storage budget – i.e., $10 million for the San Joaquin Equity Budget and $4 million for the Equity Residential HPWH Budget. Workshop will be convened to identify and remove barriers to HPWH participation.

Compared to the PD, the decision made a number of positive changes responsive to CESA’s comments, including:

• Removal of potential intent language in SB 700 decision: The decision previously suggested that an additional $100 million replenishment will be directed to the Equity Resiliency Budget, but the removal of this language may suggest that the new funding allocation will be broader than just that budget category.

• Addition of Multifamily Affordable Solar Housing (MASH) Program Cross-Eligibility: The decision was revised to recognize similarities in eligibility requirements for MASH and SGIP as well, creating greater streamlining between SGIP and MASH, not just with the other previously cited low-income solar programs like SASH, DAC-SASH, and SOMAH.

• Expansion of Equity Resiliency Budget eligibility to customers in Tier 2 High-Fire Threat Districts (HFTDs): The decision also added 911 call centers as eligible.

• Increase in Equity and Equity Resiliency incentive rates: The decision revised the Equity incentive rate from $0.65/Wh in PD to $0.85/Wh in the final decision and the Equity Resiliency (and the SJV pilot) incentive rate from $0.85/Wh in the PD to $1.00/Wh in the final decision to address the primary barrier to participation being lack of access to financing or capital. The PAs will have authority via a Tier 3 Advice Letter to modify any of these rates. The decision clarified that a developer cap does not apply to the Equity Resiliency Budget.

• Increase in incentive for discharge duration of 4 to 6 hours: The decision increased the incentive from 25% of base incentive to 50% of base incentive due to the benefit it can provide in addressing system ramping.

• Additions to the application form around resiliency: The decision responded to the IOUs concerns around ensuring that developers substantiate their project capabilities in “less-than-favorable” conditions during resiliency events to the PAs and provide this information with signed attestations to the customer. This addressed the disclosure concern.

• Affirming budget transfer from Generation Budget to Equity Resiliency Budget: No changes were made in this regard, though the decision recognized the comments made by the fuel cell and gas parties around resiliency potential from generation projects and added that this issue could be addressed in the SB 700 decision.

• Affirming heat pump water heater eligibility and carve-out: The decision focused on the need to adapt the GHG requirements for HPWHs in the Thermal Storage Working Group and rejected arguments for its ineligibility. A HPWH workshop will be held some time in December 2019.

• Deferral on defining Equity Resiliency Budget eligibility based on PSPS Zones: The CCAs raised this point about how de-energization risk is tied to these “PSPS Zones” that may not entirely line up with the CALFIRE’s fire zone tiers, but the decision commented that these zones have not yet been well-defined, thus deferring on using such definitions for eligibility.

While the above changes or affirmations are positive and in line with CESA’s recommendation and comments, the decision also deferred on defining Equity Resiliency Budget eligibility based on PSPS Zones until they are more well-defined and increasing the system sizing incentive structure to a future decision. In sum, CESA landed favorably on many of these changes and was able to defend certain problematic comments from other parties. If the GHG requirements are implemented before January 2020, the CPUC has given the PAs authority to launch the modified Equity Budget and new Equity Resiliency Budget categories as early as January 1, 2020 but no later than April 1, 2020.

SGIP Measurement & Evaluation

2014-2015 Impacts Report

On November 7, 2016, Itron released its 2014-2015 SGIP Impacts Evaluation Report, which showed that energy storage may have increased GHG emissions for that year. Notably, the report found that PBI projects fared better in terms of capacity factor, roundtrip efficiency, coincident peak demand reduction, and GHG impacts than non-PBI projects. The findings are not damning but do highlight that SGIP projects often respond to retail rates that do not always align with grid needs, creating a situation where GHG savings do not always meet expectations.

CESA finds many of the assumptions (e.g., no use of a build margin) and data quality (e.g., small sample size) to be problematic and has prepared analysis of the flawed methodology. A key challenge in the report was that there was only a few energy storage projects with sufficient data to review for the 2014-2015 period. For example, there was no information available on solar-plus-storage projects and most of the residential project data were inadequate for review. In addition, only 12 projects had corresponding load data, requiring Itron to draw some conclusions on performance without much matchable data. Overall though, CESA is supportive of the findings in terms of energy storage operational data being available for the first time to conduct such an evaluation, and presented constructive feedback on how to improve the analysis.

On December 12, 2016, the CPUC held a workshop to discuss the Itron report as well as consider future opportunities for program evaluation. The report noted how some SGIP-funded energy storage projects performed poorly in terms of round-trip efficiency, usage, cycling, and GHG emissions. CESA presented at the workshop on how the energy storage industry is still maturing and on how energy storage operations are being directed by outdated rate designs, which may not always correspond with the latest grid conditions. The CPUC Energy Division staff was responsive to this concern.

On January 13, 2017, the CPUC’s Energy Division staff published the final SGIP M&E Plan, pursuant to D.16-06-055:

• Public website for SGIP performance data for PBI projects: For energy storage projects, the publicized information includes the number of charging and discharging events and the total amount of energy charged and discharged to be published in 2017.

• Biannual impact evaluation reports: Impact analysis on certain key criteria will be conducted for the 2016-2017 and 2018-2019 periods.

• Annual impact evaluation reports for energy storage: This report recognizes the desire to monitor storage projects given the large share of funding for energy storage. Information in this report in addition to items required for the biannual impact evaluations include net GHG emissions, timing and duration of charge/discharge, and quantification of avoided capital costs.

• Annual PA review reports: These reports ensure that the SGIP Program Administrators (PAs) are held accountable for being helpful and clear in their administrative roles.

• Biannual SGIP fiscal performance reports: These reports will be issued in 2017, 2019, and 2021.

• Final program summary report: This final report will cover overall program performance from 2001-2020, including a metric for achievement of “market transformation” defined as "whether the market for the products and services supported by SGIP is self-sufficient in the absence of the program".

Note that a cost-effectiveness study is not required at this time for 2016-2020. A market transformation report is still under review at the CPUC; a further report of this nature will not be required at this time. The final SGIP M&E Plan added that information on customer load, utility, and participating tariff is required and required developers to use data request template (including 15-minute interval data from inverters) and to have single point of contact. The plan also clarified its intent to maintain customer confidentiality.

On February 16, 2017, CESA met with Itron and the CPUC to provide input on data collection plans for the upcoming 2016 SGIP Annual Review of PBI and non-PBI energy storage projects. Given the data issues, the M&E team (Itron and E3) agreed to share their plan in advance of asking for data. CESA raised concerns on the timing of the data request, intellectual property protections, heavy burden of collecting certain data types, and provision of customer load and grid status data. 

On June 2, 2017, a quarterly workshop was held that included some discussion on M&E improvements and challenges. In particular, the PAs and the CPUC were interested in learning about ‘why’ energy storage systems are charging and discharging. However, data quality and access were cited as difficulties for M&E of non-PBI projects, while potential improvements to data accuracy were suggested for PBI projects (i.e., moving from the current +/- 2% standard, which skews results over time, to a more accurate +/- 0.2% standard). The PAs also reported on its progress in reviewing applicants seeking “California supplier” status under the new, more stringent eligibility rules, noting that there are currently none approved and only a few pending review.

Energy Storage Impact Evaluation Report

On October 9, 2017, the 2016 Energy Storage Impact Evaluation Report from the M&E contractor (Itron) was released as the first in a series of annual impact evaluations that are focused on energy storage. Itron evaluated 716 BTM energy storage projects installed by residential and non-residential customers, for a total of nearly 49 MW of SGIP-rebated capacity. The non-residential energy storage projects comprised 96% of the SGIP-rebated capacity, with residential energy storage projects comprising the remaining 4%. Itron did not assess the GHG impacts of residential energy storage because data quality from the residential AES projects “prevented a detailed assessment of impacts for residential customers.” The data quality issues of residential projects included large and frequent gaps in available data, and discharge events were so small that it was not possible to determine whether it was parasitic load or measurement error.

To evaluate the GHG impacts of non-residential energy storage projects, Itron determined the marginal power plant GHG emissions rate for each 15-minute interval in 2016, then calculated the GHG emissions for each customer’s load profile with the energy storage project and without the energy storage project. The difference between the two emissions profiles of each project represents the GHG impact of that project. Itron found that the non-residential energy storage projects increased GHG emissions during 2016. Energy storage projects increased GHG emissions regardless of whether the project received performance-based or upfront incentives, but the net increase in GHG emissions per rebated capacity was greater for non-PBI projects. The increased GHG emissions occurred even for projects that complied with the existing RTE requirement.  While PBI projects generally met the existing RTE requirement, they nevertheless produced a net increase in GHG emissions. Non-PBI projects failed to meet the existing RTE requirement, and produced a greater net increase in GHG emissions per rebated capacity than PBI projects. The mean capacity factor was 2.3% for non-PBI projects and 8.1% for PBI projects, whereas the program goal for PBI projects is 10%.  The mean observed RTE was 44% for non-PBI projects and 74% for PBI projects over the entire evaluation period, whereas the program goal is a 66.5% ten-year average.

Itron modeled the simulated dispatch of energy storage projects.  The results showed that depending on their operation, even projects with low RTE can reduce GHG reductions.  If energy storage projects charge only when a zero-emissions resource is on the margin, the result is a net reduction in total emissions, even for projects with a low RTE. Whether energy storage projects reduce GHG emissions is more closely correlated with when they charge and discharge rather than with their RTE. Key takeaways from the report include the following:

• There is a misalignment between customer non-coincident peak and system peak, but the CPUC will need to address how to balance cost-causation principles (e.g., distribution capacity at feeder or line segment level) with policy objectives in rate cases.

• There is a lack of a strong system signal (e.g., load shift product, GHG signal) to discharge in any other way than to provide customer benefits.

• Redrawing peak periods will not be enough to incent changes in customer behavior, as time-varying price differentials are not as sharp a signal as demand charges or DR events, which leads to energy storage systems charging and discharging during peak periods to ensure a sufficient state of charge.

• Real-time or critical peak pricing mechanisms may better transmit utility marginal costs and improve grid services behavior.

• RTE alone is not a predictor of improved grid impact and environmental benefits and some sort of GHG signal may be needed to support GHG emission reducing behaviors.

Overall, the tone of the Itron report and its recommendations are relatively fair and nuanced. D.17-10-004 concluded that it would not adopt the grid services eligibility requirements as originally proposed, but the Commissioners stated their intent to explore program design changes that would ensure that energy storage systems are operated for grid and GHG benefit at the October 12 CPUC meeting.

On November 15, 2017, a workshop was held to discuss the report, where multiple stakeholders including E3, Itron, CESA, Stem, AMS, and PG&E presented. The Itron report observed that TOU rate changes by the IOU will provide more up-to-date signals to energy storage systems and how ‘sharp’ signals like coincident demand charges can yield a response from energy storage systems. The optimal dispatch results from E3 (below) aptly summarize the crux of the issue in which there are tradeoffs to dispatching a system for customer benefit for bill savings versus dispatching a system for GHG benefit. It underscores how current retail rates do not align customer and utility benefits for the dispatch of BTM energy storage, which could be better achieved through non-coincident demand charges.

CESA recognized the hard work by the CPUC, Itron, and PAs in producing a helpful M&E report and voiced its support for efforts to consider enhancements that build on the program’s market transformation goals. CESA has developed messaging to focus on rate designs and signals focused on marginal GHG emissions, rather than prescriptive requirements or charge/discharge schedules. In addition, with the findings of this report potentially affecting energy storage eligibility in other areas (e.g., DR programs), CESA has developed messaging to dispute points that energy storage resources are inherently GHG increasing resources. Even a perfectly efficient energy storage resource can worsen emissions if it lacks signals on when to charge or discharge. Specifically, CESA suggested the use of public Working Groups in Q1 2018 to consider solutions that inform the public record, which may include providing additional dollars to projects to direct additional behaviors, providing additional dollars to projects for expansions, if appropriate, and establishing new opt-in tariffs to direct cycling timing, as the CPUC works to update TOU rates and periods. In the meantime, CESA also highlighted how there we are working with the CAISO on a new load shift product that may also help signal grid conditions to BTM resources in a helpful way. Importantly, it will be important to push back against attempts by the IOUs to focus on utility dispatch models and prescriptive charge and discharge schedules. In particular, PG&E presented on their proposal for a “no charge period” between 12 pm and 9 pm or between 4 pm and 9 pm, which aligned with the highest GHG emitting hours. Such solutions are non-starters as they reduce the flexibility of the solution to pursue multiple applications and do not optimize for customer benefit. CSE was a more reasonable PA that found that idle losses are significant GHG drivers and recognized that changes to cycling requirements can have either beneficial or adverse impacts based on when they are cycled.

On November 22, 2017, Stem filed a PFM that sought to modify D.15-11-027 to remove the roundtrip efficiency (RTE) requirement that determines the eligibility of energy storage resources to participate in SGIP. Stem cites Itron’s report as evidence on how this is a flawed metric in evaluation and how a more refined approach is needed that actually measures GHG impacts, but also pointed to how RTE as an eligibility factor may prohibit the use of standalone energy storage as a DR resource unless it meets the program’s GHG metric, due to a decision (D.16-09-056) made in the DR proceeding. Importantly, Stem noted that energy storage operations to meet the RTE requirement may serve to increase GHG emissions. In suspending the RTE requirement, Stem thus recommended that the CPUC adopt interim measures as a more permanent RTE replacement metric is developed.

CESA supported the development of “replace” solutions through an aggressive series of biweekly Working Group meetings starting in January 2018 in collaboration with the CPUC, SGIP PAs, Itron, and member companies. The goal of this Working Group effort would be to lead a study effort to test a shortlist of different approaches for achieving GHG emissions reductions, with funds from the programs measurement and verification budget to cover the costs for conducting the study and for paying participating energy storage systems. This collaborative Working Group could work to deliver a report by Q2 2018 and implement any new solutions by late 2018 or early 2019. However, CESA did not advocate for a temporary repeal of the RTE requirement, instead arguing for the RTE requirement to be a “spec sheet” eligibility standard. CESA expressed support for the program’s goal of achieving GHG emissions reduction and focused on the following points:

• Current retail tariffs are insufficient to drive energy storage dispatch in a manner that will reduce GHG emissions.

• Absent better GHG market signals, enforcement of the RTE requirement may, in the near term, have the unintended consequence of increasing GHG emissions from some projects.

• A CPUC-directed working group should be established to urgently develop and vet additional GHG emission reduction signals.

• CESA supports retaining a “single-cycle” RTE requirement as an upfront technology eligibility standard for energy storage systems.

• The program should remain open while additional GHG emission reduction-oriented solutions are established and interim solutions (e.g., emission allowances) can be considered.

Most other parties (SCE, PG&E, CSE, ORA, and CALSEIA) supported a working group process to develop interim and/or long-term replacement solutions to the RTE requirement, which was largely agreed to be not the most accurate metric. However, parties differed on some interim steps to take to address the GHG issue.

See CESA's comments on December 22, 2017 on Stem's PFM. 

On September 7, 2018, the annual impact evaluation report on energy storage systems was released that found that energy storage systems continued to result in a net increase in GHG emissions but the CPUC noted that these results were somewhat to be expected since the main driver of this behavior (i.e., misalignment between retail rates and grid needs) has not changed between the 2016 and 2017 evaluation periods. Note that the 2017 evaluation included a number of projects that were added over the past year, as well as already including all the same projects from the 2016 evaluation. As compared to last year, the key modifications in the 2017 evaluation also included adding estimates of criteria air pollutant impacts, more deeply analyzing participation in DR programs, and estimating the impact on local distribution feeders. In addition, with new GHG rules not to be implemented until Q2 or Q3 2019, the CPUC Staff set expectations that the impact of those rules may not be seen until the 2019 or 2020 evaluations.

The evaluation examined performance against capacity factors (CF) and RTE. Itron defined CF as a measure of system utilization and calculated it as the sum of the storage discharge (in kWh) divided by the maximum possible discharge within a given time period. The SGIP Handbook requires that PBI projects achieve an CF of at least 10% to receive full payment. Itron defined RTE as the total kWh discharge of the system divided by the total kWh charge and, for a given period of time. Annual RTE is different from single-cycle RTE, as the former accounts for idling of systems. Given those definitions, Itron found that PBI projects fared the best and that standby losses and parasitic loads for non-PBI projects over the course of a year had a substantial impact on the resulting CF and RTE values, especially for energy storage systems that were under-utilized and frequently idling. For customer impacts, Itron generally found that non-residential projects followed retail energy rates and reduced customer peak demand, though a significant percentage of projects did not follow expected behavior from TOU arbitrage, indicating that there are other factors (e.g., non-coincident demand charges) driving dispatch behavior. These results are similar to what was found in the 2016 evaluation.

The main finding in the report was that SGIP energy storage projects increased GHG emissions on average, with parasitic losses accounting for roughly 10% of the net GHG increase for non-PBI projects. However, Itron also conducted simulated optimal dispatch using new TOU rates, which are approved and implemented in SDG&E and in the process of approval in PG&E and SCE but were not applicable to any of the energy storage projects in the sample. Under this simulated analysis, the avoided cost benefits increased by 178%.

Other key findings from the Itron analysis included:

• Energy storage systems that were participating in DR programs and were net discharging throughout the respective DR event hours also decreased GHG emissions and provided a net utility cost benefit, with the magnitude of GHG emissions reductions depending on the number of event calls, event durations, and size and count of energy storage systems.

• Projects with the highest RTEs also tend to have the highest CFs but simply increasing CF for the sake of increasing RTE alone will likely not turn energy storage projects into net GHG reducers.

• If energy storage is modeled strictly as a load modifier (a proxy for business-as-usual), it is forecasted to produce a slight increase in overall system costs over the 2018–2030 horizon, so energy storage should be dispatched for system-level benefits and be able to provide energy, contingency, and operating reserves in DR programs and CAISO markets.

• Since many residential projects in the sample were on tiered, non-TOU rates, Itron could not quantify if and when residential energy storage systems provided backup services.

• There was no discernable difference in performance between energy storage systems co-located with PV and standalone energy storage systems, indicating that energy storage projects paired with PV were not prioritizing charging from PV.

In sum, the results of this new annual impact evaluation are nothing different or new from the year before, except that the sample of projects to draw from has increased. CESA appreciated that the CPUC added a foreword to the report to provide some context in interpreting the results, but one key area of concern may be that the results suggest some increase in cycling, albeit at times of grid benefit, may better achieve the program’s goals of grid support and GHG emissions reduction. As became evident in the Staff Proposal recommending some operational requirement changes, the CPUC appeared to believe that making such changes to increase cycling, especially for small non-residential and residential systems, and adding more punitive penalties would support achieving program goals.

SGIP Funding

Background

In 2014, SB 861 and AB 1478 extended the SGIP for another five years through 2019. The SGIP will receive $83 million per year for a total of $415 million, funded by rates.

On March 10, 2017, the PAs held a workshop to discuss new SGIP rules and procedures, new database and application functionality, and next steps in SGIP including potential storage operation rules and budget scenarios. Energy Solutions also provided a demo of their SGIP portal. Importantly, the PAs revealed that the program will have a 'soft opening' where applicants can log into the portal and begin working on application materials, and open the program for application submissions and reservation requests on May 1. The program will open with approximately $40 million in already-authorized funds in Step 1, in addition to funds from cancelled projects (rumored to be in the $30-$40 million range) and application fee forfeitures.

SB 700 Implementation

On April 15, 2019, a Ruling was issued seeking comment on implementation of SB 700, which authorized the CPUC to extend annual collections for the program for five additional years, from December 31, 2019 to December 31, 2024, and extends administration of the program for five additional years, from January 1, 2021 to January 1, 2026. The Ruling sought feedback and responses on several program design areas. CESA supported key program modifications but added that the CPUC should view SGIP as a market transformation and technology deployment program and strive to avoid making program rules and processes overly complex, while still being a sophisticated program that effectively achieves its goals. For each of the questions and topic areas, CESA addressed them as follows:

• Overall collection levels for years 2020-2024: CESA recommended that the CPUC authorize the full amount to be collected evenly across 2020-2024 years ($166M/year), based on IRP models showing the need for storage and on our calculations for how much storage will be needed in addressing solar integration. Unallocated funds through 2019 should be carried over into 2020-2024 funds.

• Funding allocations among technology and customer sectors: CESA recommended that a vast majority of SB 700 funds be directed to energy storage, given historical participation levels. Additionally, CESA recommended funds be allocated for each step as follows: 20% to Small Residential, 20% to Large, 20% to Equity (of which 20% to Residential Equity), and 40% to General (available to all). CESA argued this provided flexibility if estimated and actual market size and demand for each did not entirely match.

• Administrative budget: CESA recommended that the CPUC leverage excess administration funds on ME&O activities for Equity Budget and streamlining processes for all projects, as well as on potentially re-allocating some to incentives.

Opening comments were filed by a number of parties. CESA observed a number of areas for potential comment, especially as SDG&E and SoCalGas continued to criticize the program as being irreparably ineffective. The utilities and PAO generally opposed full funding collections as authorized in SB 700 at this time, conditioning it on funding utilization levels and GHG performance results. In response, CESA commented on how full funding authorization from SB 700 is needed to provide long-term market certainty and to strive to achieve energy storage's market potential and that further studies or reports are not needed to assess the barriers to non-residential storage participation. CESA added that market transformation in different storage customer categories should be preserved and that proposals for annual incentive budget structure should not be adopted.

See CESA’s comments on May 30, 2019 and reply comments on July 12, 2019 on the Ruling

On December 11, 2019, a PD was issued that proposed to authorize ratepayer collections of $166 million annually for the years 2020 to 2024, pursuant to SB 700, and to prioritize allocation to customers affected by PSPS events or located in areas of extreme or elevated wildfire risk, pursuant to AB 1144. Out of the fully authorized collections, energy storage technologies will receive 85% of funds, up from 80% in previous funding allocation decisions (i.e., see AB 1637 decision). To provide some funding certainty for some time, the PAs would be authorized to submit advice letters to transfer funds between energy storage and generation incentive budgets subsequent to December 31, 2023. The 10% and 7% administrative budgets were approved for CSE and SoCalGas, respectively, while PG&E and SCE must use accumulated unused administrative funds, thus ensuring that most of the collections go toward incentive funding. The following allocations were proposed for adoption:

For the Large-Scale Storage Budget, the PD proposed to eliminate the adjustment for the Federal ITC for equipment purchased after December 31, 2021 for all Large-Scale Storage Budget categories but opted to maintain incentive rates since there is not enough information that it is too low. Instead, the CPUC sought to address a potential barrier in a precautionary manner, pointing to the impact of rate changes, new GHG requirements, and “chilling effect” of ITC step-down for longer lead-time projects. Contrary to comments from SCE, the PD declined to adopt an annual step-down structure as the current structure supports market transformation through a competitive process. It also directed a 20% developer cap to reflect new statewide budgets for Steps 3-5.

For the Small Residential Storage Budget, the PD proposed to create two new steps with equal funding allocations that decrease by $0.05/Wh for Steps 6-7. In doing so, the PD seeks to “maximize the number of customers able to access incentives.” Despite CESA’s comments, the PD found no evidence that $0.20/Wh makes residential projects uneconomical since demand has been high in 2019. Beyond economics, customers may find primary value to be backup power.

For the Equity Resiliency Budget, the PD proposed to maintain the Equity incentive rate ($0.85/Wh) and Equity Resiliency incentive rate ($1.00/Wh) with no step-down structure but expanded eligibility to include residential and non-residential customers “whose electricity was shut off during two or more discrete PSPS events prior to the date of application for SGIP incentives”. The October 2019 PSPS events provided new information to support updating eligibility criteria (e.g., lists are available from IOUs), but PD declined to determine this by “PSPS zone” that has yet to be defined. In either case, the customers must be otherwise eligible for Equity Resiliency – e.g., critical facilities for non-residential customers. The PD also defined additional customers as having critical resiliency needs:

• Markets (groceries, supermarkets, corner stores) are added as non-residential customers if they are a small business ($15M or less in last three tax years) – allows purchase of necessities and find air-conditioned space

• Households relying on electric-pump water wells are added as customers to address drinking water, sanitation, and fire-response needs (does not define as residential but presumably so)

• Independent living centers are added as non-residential customers to support individuals with disabilities (uses 29 U.S. Code § 796a definition)

• Food banks (soup kitchens, hunger relief centers, food pantries) are added as non-residential customers to ensure essential food sources for lower-income families (uses U.S. Code § 7501 definition)

A new aspect of the PD was the addition of a $0.15/Wh resiliency adder for non-Equity Large-Scale Storage projects where the adder is estimated to cover 50% of costs through Step 5 for non-residential projects, whereas no adder is needed for residential projects given market demand already and Equity incentives in place (which should be priority). The same eligibility requirements for the adder was in place other than for customers needing to meet the equity-related requirements. In lieu of a residential resiliency adder, the PD adopted 50% “soft target” for general Residential Storage Budget to be reflected in an evaluation. To meet the AB 1144 requirement, applications are required to notify local governments that they intend to or have installed onsite storage or renewable generation. For all General or Equity storage projects, the PD adopted a duration-based step-down structure as follows: 100% (0-4 hours), 50% (4-6 hours), and 0% (>6 hours). In doing so, the PD said it will encourage resiliency for all storage customers but reminded how they must still meet grid and GHG requirements.

Finally, for the Renewable Generation Budget, the PD increased the base renewable generation technology incentive to $2/W with no step-down structure, with $5 million per project cap in recognition of the GHG emissions reduction and higher incentive needed to cover increased cost of renewable biofuels, though the directed biogas requirement is maintained. Furthermore, the PD adopted a $2.50/W resiliency incentive adder to support prioritized outreach to customers with critical resiliency needs, which helps cover the general economic need while prioritizing PSPS customers. While CESA members are likely not invested in changes to the Renewable Generation Budget, the PD’s conclusions highlighted how the fuel cell parties were able to secure rich incentive rates with their substantiation of the higher costs for deployment.

As next steps, the PD proposed to accelerate the effective date for implementation of the GHG emission reduction requirements and acceptance of applications for small-scale equity resiliency residential projects to no later than March 1, 2020 since the scale and scope of the October PSPS events warranted this change. Through this is slightly later than the PAs’ proposed timeline, the PD does ensure a “backstop” effective date to get resiliency projects moving for small residential customers. Furthermore, to support efficient deployment of funds, the PAs were directed to process incentive applications within 45 days of receipt, with priority toward Equity Resiliency Applications. The 97-day timeline from Large-Scale Storage application submission to incentive reservation is unacceptable for PSPS needs.

CESA supported some of the larger decisions in the PD but recommended several modifications to the PD to better ensure that SGIP funds are directed to most effectively and efficiently address customer resiliency needs ahead of the 2020 and 2021 wildfire seasons while supporting continued storage deployments generally to achieve the program’s multi-pronged objectives.

See CESA’s comments on January 3, 2019 on the Proposed Decision

Though many of the proposed modifications are well-intentioned and generally effective, CESA believed certain refinements are needed to improve program outcomes and ensure a meaningful amount of deployment, which requires a recognition of some of the on-field realities of deploying resilient systems. Specifically, CESA recommends the following to overcome the major barriers to project deployment:

• The General Large-Scale Storage Budget incentive rate is too low if unchanged and should be adjusted upward by $0.10/Wh for each step to support market deployments in the commercial sector.

• A ratchet-up mechanism should be implemented for General Large-Scale and Small Residential Storage Budget categories to avoid stalled budget categories.

• Cycling requirements for energy storage systems claiming the resiliency adder or Equity Resiliency incentive funds should be reduced to 52 cycles per year to support resiliency objectives given that new GHG rules and performance incentives are in place.

• Eligibility for the resiliency adder and the Equity Resiliency Budget should be modified to not only allow PSPS-affected customers but also allow customers in Tier 2 or Tier 3 High Fire Threat District (HFTD) zones.

• Schools should also be added as eligible non-residential customers for the resiliency adder and the Equity Resiliency Budget.

• System sizing rules should be revisited to support the deployment of proper resiliency projects.

• The developer cap should be lifted after a certain period of time in a given step budget category to support utilization of these funds.

• This decision should affirm the Equity Resiliency Budget launch date as being no later than April 1, 2020, which is open to interpretation in D.19-09-027.

On January 27, 2020, D.20-01-021 was issued that was revised as follows:

• Funding allocation: Heat pump water heaters were allocated 5% of SB 700 funds ($44 million) after having been overlooked in the PD with no additional allocation. The CPUC justified this change due to the GHG potential of HPWHs, which cannot be realized without a meaningful funding allocation. The additional funds came from a reduction in the General Large Scale Storage Budget (down to 10% from 12%) and the Renewable Generation Budget (down to 12% from 15%), with reductions from the latter being justified based on reporting and validation concerns of directed biogas projects that require further investigation. To allow for additional flexibility, the PAs were authorized to be able to transfer funds one year earlier than previously proposed, starting on December 31, 2022 instead of December 31, 2023. The revised PD did note that funding allocation changes can still be proposed by CPUC staff, ALJ, or Commissioner at any time.

• General Small Residential Storage Budget: The revised PD established more detail related to the “soft target” for general residential incentives where PAs would be directed to pause SGIP applications for customers who do not meet the resiliency-related eligibility criteria if such customers constitute more than 50% of SGIP incentive claims in a given step.

• General Large Scale Storage Budget: The revised PD did not make modifications to the incentive rate, noting that no new factual information was presented in comments.

• System sizing rules: Sizing limitations based on inverter size for resiliency-related projects are removed, and full incentives for systems sized above peak load are allowed upon demonstration of need. However, since the details are complex, the PD deferred to the PAs to allow them to submit any additional revisions in the advice letters. The PD also clarified that electrical and critical load panel and wiring upgrade costs are allowable costs for resiliency projects.

• Developer cap: The revised PD directed the PAs to submit a Tier 2 advice letter suspending or modifying the developer cap if the incentive step has been open at least 12 months, at least two entities have reached their cap, and there is otherwise low participation in the incentive step, leaving some discretion to the PA and CPUC staff, especially with a consideration of overall resiliency needs.

• Customer eligibility: The revised PD directed the PAs to establish a working definition of “discrete PSPS event” but indicated that they may narrow the eligibility criteria in the future due to grid hardening and resiliency investments. For markets, the $15-million annual revenue criteria was clarified as applying to a single location. To support developers, the IOUs are directed to ensure a method of customer identification as well as a master list of all circuits that have experienced two or more PSPS events.

• Implementation timeline: A three-stage advice letter process has been added to ensure Equity Resiliency Budget launch for residential customers by March 1, 2020 and for non-residential customers by April 1, 2020: (1) supplemental advice letter within 12 days of decision adoption for residential customers; (2) advice letter by February 18, 2020 for non-residential customers; and (3) advice letter within 90 days of decision adoption for all other program revisions and budgets adopted in this decision.

• Program administration: The PAs are directed to adhere to a 45-60 day timeline for fully processing incentive applications to support streamlining. Meanwhile, the revised PD declined to carve-out dollars to local partners, instead recommending that the PAs develop a “customized” marketing, education, and outreach (ME&O) plan.

Overall, the modifications were a mixed bag in the sense that, on the positive side, CESA was able to secure some key clarifications to the launch dates of the Equity Resiliency Budget, get modification to the developer cap rules that were somewhat in line with CESA’s recommendations, have system sizing rules modified to accommodate resiliency projects, and have the PAs be directed to support customer identification. However, many of the major recommendations around increasing the General Large Scale Storage Budget incentive rate and broadening customer eligibility criteria were unchanged. Meanwhile, funding allocation flexibility was only slightly improved, but it could be seen as becoming more prescriptive with the new “soft target” rules for general residential storage projects. Despite these changes, there may still be opportunity to fix some of these detailed issues through the implementation advice letter review process.

On April 15, 2020, PAs submitted a joint advice letter that proposed revisions to the SGIP Handbook to address the remaining orders in the SB 700 decision (D.20-01-021), including funding collections and allocations for the different budget categories and for PA administrative expenses. Funding authorized in this decision became available on July 20, 2020, where projects on the waitlist for these budgets will receive funding in the order in which they were submitted to the application portal. Any remaining funds will be available to new applications.

On June 9, 2020, CESA requested that the CPUC issue a Ruling as soon as possible to: (1) transfer $150 million in funds from the Equity Resiliency Budget and $150 million in funds from the General Large-Scale Storage Budget to the Non-Residential Storage Equity Budget; and (2) to transfer $10 million in funds from the General Large-Scale Storage Budget to the Residential Storage Equity Budget. CESA justified the request on the following grounds:

• Immediate fund transfers to the Equity Budget will support shovel-ready projects that provide economic stimulus and support the CPUC’s long-held equity goals while addressing gaps in the Equity Resiliency Budget.

• The majority of waitlisted projects in the Non-Residential Equity Budget can be reasonably assumed to support resiliency based on the storage durations in the Reservation Request Form data.

• Potentially sufficient funds are in place are in place in the Equity Resiliency Budget to support many customers in need as well as in the Large-Scale Storage Budget to support general customer needs.

See CESA’s motion on June 9, 2020 requesting CPUC Ruling

Responses were submitted by several other parties where SoCalGas, SCE, and PG&E highlighted how the motion is procedurally improper, while PG&E GRID Alternatives, and Sunrun partially supported the request to transfer money only from the General Large-Scale Energy Storage Budget. However, GRID Alternatives fiercely defended the Equity Resiliency Budget, citing some PSPS customer data and attaching opposition letters from the DAC Advisory Group and a grassroots disability organization.  CALSSA, meanwhile, presented a modified request to transfer only $100 million from the General Large-Scale Energy Storage Budget to the Non-Residential Equity Budget, $80 million from the Equity Resiliency Budget to the Non-Residential Equity Budget, and $20 million from the Equity Resiliency Budget to the Residential Equity Budget. However, GRID Alternatives fiercely defended the Equity Resiliency Budget.

In response, CESA argued that a motion is the appropriate procedural vehicle for the requested relief since no change is being made to D.20-01-021 and based on the CPUC’s statutory authority. CESA added that the transfer request from the General Large-Scale Storage Budget is generally unopposed while merits still exist for the transfer request in full or in part from the Equity Resiliency Budget.

See CESA’s reply to responses on the motion on July 6, 2020

On June 10, 2020, CESA submitted a PFM to re-authorize the PAs’ ability to transfer funds. Specifically, CESA recommended that D.20-01-021 be revised to remove the moratorium on this fund transfer authority until after December 31, 2022. In addition, CESA recommended that the CPUC adopt the following lottery prioritization criteria for any future over-subscriptions that may occur as a result of granting CESA’s concurrent Motion and/or due to fund transfers requested by the PAs if the Commission grants this Petition:

• Customers who meet the Equity criteria

• Customer represents a critical facility or school that serves eligible DAC customers

• Storage system provides backup power and the applicant meets all of the existing backup documentation

We argued that this PFM was warranted for the following reasons:

• Recent program incentive uptake and waitlist data suggests that the moratorium period until December 31, 2022 would lock funds from being used and useful and create instability to serve Equity customers who seek storage for resiliency.

• The Tier 2 advice letter process still ensures that the Commission can enforce its program priorities and goals while providing parties with an opportunity to protest and respond to any requests to transfer funds.

• The currently existing lottery system and priorities need to be updated to reflect the CPUC’s near-term priorities and objectives.

In order to simplify the request in a concurrent motion, CESA decided to make a separate request to grant PA fund transfer authority and set the lottery prioritization criteria to supplement our motion. With few or no rule changes required in the fund transfer request, CESA aimed to ease implementation while allowing the broader rule changes to be addressed separately. With this Petition, CESA was seeking to ensure a backup plan if our Motion was not granted while offering greater flexibility going forward to avoid the huge backlog of projects currently on the Equity waitlists.

In response, GRID Alternatives argued that a fund transfer from the Equity Resiliency Budget is not warranted since those funds provide critical resiliency to the customers in most need. The Joint PAs agreed with modifying the moratorium on fund transfers for the reasons CESA laid out in its PFM, while supporting changes to the lottery priorities based on the SGIP eligibility criteria for the discrete budget categories, such that their proposal to “maintain the lottery mechanism” presumably means that waitlisted reservations will be “cleared” by order of submission. CALSSA also supported the new prioritization criteria but opposed the removal of the preference for solar paired projects, while MCE supported the change with “early” transfers only being allowed when shifting funds within budgets for the same technology types and from lower-priority to higher-priority categories. Shell, by contrast, did not object to the PFM but recommended the introduction of incentive steps to extend funds to a broader base of customers and the re-imposition of the developer cap.

On August 6, 2020, a Ruling was issued that acknowledged CESA’s observation of an imbalance between demand for the Equity Budget categories with the available authorized budgets and thus proposed the following for comment:

• Transfer $100 million from the General Large-Scale Energy Storage Budget to the Non-Residential Equity Budget and $8.5 million from the General Large-Scale Energy Storage Budget to the Residential Equity Budget

• Update the lottery prioritization criteria for the Equity Budget categories to favor storage systems providing backup power and provide the necessary backup documentation, with the reservation of any remaining funds based on the order of the date and time the application was received

• Cap the amount any individual applicant entity can receive from the large-scale non-residential budget at $5 million per entity (i.e., per school district, city, or water district, etc.) as well as per project

PA fund transfer authority, however, would remain unchanged. In addition, the Ruling would decline to transfer any funds from the Equity Resiliency Budget due to stakeholder opposition, their status as the most vulnerable population, and the steady demand for these funds. Implementation advice letters must be filed within 30 days.

While generally supportive of the proposal in the Ruling, CESA recommended several modifications to achieve the intended effects of the fund transfer to support timely and immediate economic stimulus for Equity customers and to support a significant portion of resiliency-focused projects in the process. Specifically, CESA’s modified proposal can be summarized as follows:

• Transfer $100 million from the General Large Storage Budget to the Non-Residential Storage Equity Budget and $8.5 million from the General Large Storage Budget to the Residential Equity Budget, as proposed in the Ruling

• Apply a random-order lottery for same-day waitlisted applications received on May 12, 2020 to distribute the proposed fund transfers for the Non-Residential Storage Equity Budget and Residential Equity Budget, instead of the additional lottery prioritization criteria for systems providing backup power, as proposed in the Ruling

• Defer the development of additional lottery prioritization criteria for systems providing backup power, as proposed in the Ruling, and address the adoption of these criteria to the resolution of CESA’s Petition

• Reinstitute limited PA fund transfer authority, where by January 1, 2021, the PAs may request up to $50 million to be transferred from any budget category, as the Commission sees fit, to support waitlisted Non-Residential Equity Storage projects with additional lottery prioritization criteria in place.

• Remove the $5 million per entity cap for large-scale non-residential storage projects

While not granting the full ask, this result is also not unexpected based on market data and our conversations with Energy Division.

See CESA’s comments submitted on August 21, 2020 on the Ruling

CALSSA and Sunrun were generally aligned with many of CESA’s comments, with CALSSA adding that the entity-based cap may be unneeded because it would apply to a small number of entities and since it is unclear whether it applies to all applications or just those on the waitlist. Whereas Sunrun recommended transferring some funds from the Renewable Generation Budget instead, Foundation Windpower strongly opposed depleting their budget given lengthy project development timelines. All parties also opposed the backup priority criteria and urged for PA transfer authority to be reinstated before 2023, with the PAs commenting that some budget allocation flexibility is needed to make the transfers specific to the needs of the PA territory.

AB 1637 Implementation

On December 30, 2016, Commission President Picker issued a Ruling to seek stakeholder feedback on questions that can be used to guide implementation of AB 1637 (Low, 2016), which doubles the amount of funds collected for SGIP on an annual basis through 2019. The Ruling includes a list of questions on how the funds should be allocated across technology categories and budget steps, and whether/how operational requirements should be attached to these additional funds to address GHG emission concerns raised by the Itron 2014-2015 SGIP Impacts Evaluation Report (Itron Report). 

CESA submitted comments that can be summarized as follows:

• The CPUC should approve the full amount of increased SGIP revenues as authorized by AB 1637.

• Per legislative intent, the CPUC should allocate at least 75% of proposed new funding to energy storage technologies.

• The CPUC should allocate the additional funding for energy storage evenly across the five steps in accordance with D.16-06-055.

• Per legislative intent, the CPUC should quickly make a determination on additional funding allocation before Step 1 is opened.

• Better data on the GHG emission impacts of energy storage operations is needed before making specific changes to existing operational or performance requirements of energy storage projects.

• The CPUC should direct LSEs to immediately implement an opt-in, ‘bolt-on’ GHG Reduction Tariff for Energy Storage Charging.

• The CPUC should re-adjust the developer cap to reflect the new step budgets.

• The CPUC should direct or clarify that performance-based incentives adopted in D.16-06-055 should apply to both existing and new energy storage projects.

• The CPUC should account for and anticipate implementation delays regarding the new California supplier requirements.

The primary focus of CESA’s comments was to focus on the legislative intent of AB 1637 and lean on the existing rules and requirements per D.16-06-055 before making any fundamental changes to the program. CESA cited the limitations of the Itron Report assessment of energy storage performance as not being enough to justify corrective actions at this time. Notably, CESA proposed the idea of the ‘GHG Reduction Tariff for Energy Storage Charging’ as a future consideration but CESA did not recommend any operational/performance requirements as suggested in the Ruling.

CESA also submitted analysis of marginal emission impacts of charging at different hours of the day throughout the year to serve as a foundation for a potential ‘bolt-on’ tariff to address some of the CPUC’s GHG performance concerns of energy storage systems. This analysis was conducted in partnership with WattTime, a Berkeley-area nonprofit. CESA will continue to work with WG members to develop the details of this idea, and narrowed the focus of its comments on some preliminary analysis done on the low-GHG hours that could be used as the periods for storage charging.

See CESA's comments on January 31, 2017 on the Ruling.

On March 6, 2017, the Proposed Decision (PD) on AB 1637 implementation was issued that authorized the full doubling of funds for SGIP.  Energy storage technologies will receive the majority share of the AB 1637 funds (85%), more than what CESA minimally asked for (75%), which is great for CESA members in that there is a much larger pool of funds available. Furthermore, the PD determined that it is premature to set operational requirements at this time, clarified that the developer’s cap will be adjusted to the additional funds from AB 1637, and approved CalSEIA's Petition for Modification to fix the ITC rate for large energy storage at 72% of the non-ITC rate for large energy. On the other hand, the funds are loaded in the middle and later steps (30% in Step 3, 30% in Step 4, and 25% in Step 5) with a smaller than expected share of funds going to Step 2 (15%) and no funds going to Step 1 (0%). 

CESA focused its comments to the PD on reiterating its position that an even distribution of funds across the steps ensures market transformation of the broader industry and on requesting clarification on how the general pool of funds will work. Clarification was also sought from CESA on the allocation of canceled project funds and how the AB 1637 funds would be accessible to small residential energy storage developers. CESA also responded primarily to points raised by the IOUs in comments on the need for operational requirements. 

See CESA's comments on March 27, 2017 and reply comments on April 3, 2017 on the Proposed Decision.

On April 6, 2017, the CPUC issued D.17-04-017 on a unanimous roll-call vote that allocated AB 1637 funds with 34% to Step 2 (up from 15% in the original PD), 33% in Step 3 (up from 30%), and 33% in Step 4 (up from 30%). No additional funds were added to Step 1, while the redistribution of funds was taken from Step 5. In addition, the CPUC determined that 10% of the 85% of AB 1637 funds to energy storage should go to residential customers. The CPUC also expressed its intent to kick-start the program without delay before or after Step 1, but also have a portion of the AB 1637 funds be directed to disadvantaged communities.

Step Fund Transfer

On November 26, 2019, advice letters were submitted by PG&E, SCE, and SoCalGas requesting to transfer funds from the Step 5 Large-Scale Storage Budget category to the Step 5 Small Residential Storage Budget category. Due to market interest, the Small Residential Storage budget categories were fully subscribed for all five steps by July for PG&E, September for SCE, and October for SoCalGas.

• PG&E: Requested transfer of $4,754,962. Assuming 2020 demand stays on pace with 2019, PG&E sought two quarters worth of funds to be transferred due to PSPS-driven demand and based on Step 5 incentive rate, plus additional funds to support over 400 waitlisted projects.

• SCE: Requested transfer of $6,000,000. SCE calculated an average rate of $1 million per month based on historical data from August to September 2019 to determine that $5 million in funds would be needed to support new residential projects through April 2020 and calculated an additional $1 million is needed to support waitlisted projects.

• SoCalGas: Requested transfer of $717,771. SoCalGas simply recommended an additional 15% allocation based on a previous CPUC decision to establish a 15% carve-out for the Small Residential Storage Budget category, per D.16-06-055.

They similarly argued that this re-allocation should not impact large-scale storage projects since their budget category has sufficient funds and remains in Step 3. Similar to what CSE proposed in January 2019, these PAs also recommend that the CPUC allow the developer cap to be reset when each PAs’ advice letters have been approved to give all developers an opportunity to access this additional funding. In CESA’s view, there were no issues with the advice letters, although SoCalGas' methodology for allocating funds could be more robust, such as how PG&E and SCE looked at historical demand to 'right-size' needs while anticipating growing resiliency needs. However, the proposed modifications appear reasonable to support continued residential storage deployments while not taking too much away from the large-scale budget category.

PAO protested the re-allocation proposal because of concerns about GHG performance of residential storage systems, and as a result, recommended that projects claiming re-allocated funds be subject to the GHG requirements for new residential projects. SoCalGas agreed, but CSE defended against retroactive application of the new GHG reduction requirements and the need to modify D.19-08-001 around the April 1, 2020 cut-off date for legacy versus new projects.

On January 2, 2019, the CPUC issued a non-standard disposition letter that approved the individual PA advice letters, effective January 2, 2020, with the clarification that all new SGIP applications for residential energy storage incentives must comply with the new GHG requirements from D.19-08-001 when the Equity Resiliency Budget opens to small residential customers. The CPUC found that each PA reasonably showed demand for residential storage systems have grown in their service territory and that the transfer of funding would not negatively impact the large energy storage market since demand has slowed and considerable funding remains for those projects. The CPUC rejected the PAO’s protest since D.19-08-001 made clear the distinction with legacy projects.

Cost Allocation

On August 22, 2016, the IOUs filed Tier 3 Advice Letters with SGIP cost allocation proposals. Per D.16-06-055, the IOUs were required to determine an equitable distribution of costs and benefits of the SGIP. SDG&E and SoCalGas proposed to maintain the current cost allocation mechanism until 2020 in order to evaluate the implementation of SGIP modifications. SCE proposed to change cost recovery from the distribution component to the Public Purpose Program (PPP) charge component. PG&E originally proposed to re-allocate the electric customer class contribution based on the percentage of total incentive dollars reserved and/or paid out in its service territory, by electric rate classes in the last five years. In a supplemental filing, PG&E changed course and proposed to lock in an allocation of 10.4% of SGIP costs to residential customers, based on "forward-looking targets" of energy storage being allocated 75% of the SGIP budget. 

On September 12, 2016, several parties filed Protests. ORA protested the proposals by PG&E, SDG&E, and SoCalGas on the grounds that residential customers should not absorb half the program’s costs despite minimal amount of funds going to them. CLECA and EPUC protested SCE’s proposal because it would have departing load bear the costs of SGIP through the PPP, rather than just bundled customers under the existing cost allocation mechanism.

On October 20, 2016, TURN protested PG&E's proposal, and argued in favor of allocating costs on the basis of actual benefits resulting from the disbursement of SGIP incentives over the previous 5 years. TURN also suggests a rolling five-year average of historical spending to account for the changing SGIP design.

On January 15, 2019, CSE submitted an advice letter requesting approval to transfer funds from the Step 5 large-scale energy storage budget to the Step 5 small residential energy storage budget, which was exhausted by April 2018, several years earlier than anticipated. As justification, CSE pointed to the lack of added funding from the AB 1637 authorization and the backlog of over 500 waitlisted residential storage applications to date. CSE requested that all $4.765 million be transferred from the large-scale energy storage budget to the small-scale energy storage budget. Even as expected 2019 demand based on the 2018 pace yielded $4.458 million, CSE recommended transferring all of the large-scale energy storage budget because of the expectation that the market will grow with new companies and economic incentives from newly established TOU rates. CSE also observed that large-scale participation has been slower and should benefit from additional SB 700 funds. Notably, CSE recommended against adjusting the developer cap, which may be an issue if funds are added to Step 5 as opposed to a new Step 6 that would reset the cap. Sunrun protested CSEs proposal to refrain from adjusting the developer cap, which they argued would needlessly restrain top-performing developers from helping to meet residential storage growth in 2019. CESA supported CSE’s plan since it would involve a temporary transfer of funds from one underutilized funding bucket (Large Step 5) to a heavily-used bucket (Small Residential Step 5), with the plan to return the ‘borrowed’ funds to the Large Step 5 bucket once additional funding from SB 700 are authorized and dispersed into the program.

GHG Compliance Rules & Requirements

Background

In 2011, D.11-09-015 modified the primary purpose of SGIP from peak load reduction to GHG emissions reduction, and subsequently, the CPUC modified the program's incentive eligibility criteria to support technologies that achieve GHG reductions. 

WattTime, the GHG signal implementer for the Self-Generation Incentive Program (SGIP), made the GHG signal publicly available starting on April 1, 2020 via an Application Programming Interface (API), which include a 5-minute real-time signal (compliance), historical data, and forecast data. Forecast data will include:

• 15-minute forecast, with 5-minute granularity and updated every 15 minutes

• Hour-ahead forecast, with 5-minute granularity and updated every 15 minutes

• Day-ahead forecast, with 5-minute granularity and updated every 15 minutes

• 72-hour ahead forecast, updated hourly

• Month-ahead forecast, updated daily

• Year-ahead forecast, updated monthly

GHG Compliance Rules

On November 19, 2015, the CPUC issued a Final Decision (D.15-11-027) on the GHG emissions eligibility factor (which was an improvement over the initial Proposed Decision, and made the greenhouse gas (GHG) emissions reduction factor requirement (from 379 kg-CO2/MWh to 334 kg-CO2/MWh for most technologies) more stringent, with further lowering of this level year-over-year as California advances toward a 50% RPS. D.15-11-027 also increases the round-trip efficiency levels for storage technologies from 63.5% to 66.5%. The CPUC explains this increase is due to the use of a 1% annual degradation factor for energy storage.

See CESA's comments on July 30, 2016 and reply comments on August 4, 2016.

GHG Signal

On December 29, 2017, a Ruling was issued that entered the November 15, 2017 workshop on the 2016 SGIP Energy Storage Impact Evaluation Report into the record and established a working group to improve GHG emissions reductions from energy storage systems, such as by providing a “GHG signal” to participants in advance to support the operations of energy storage systems for GHG benefit. The working group was tasked with developing new rules and/or operational requirements to be considered in the next several months and with proposing a verification and enforcement mechanism to ensure system performance. The Ruling also directed the working group to develop a GHG signal with the following minimum characteristics:

• The marginal GHG emissions of the grid reported for either NP 15 or SP 15, as applicable

• In 60, 30, 15 or 5 minute increments as determined by the working group

• Forecasted for the day ahead

• Automatically transmitted to the energy storage system or to the controller of the system if systems are controlled remotely

Finally, the Ruling noted that consensus from the working group is preferred, though not required. The CPUC Energy Division will then recommend a methodology. The goal is for the working group to file a report and potentially a joint filing of recommended SGIP changes by April 2.

On January 9, 2018, the working group kicked and continued to meet weekly in February and March. Parties reached an agreement on the load profiles and old/new rates to be used in the modeling exercises and tentatively agreed on the technical RTE and parasitic losses as inputs to the modeling. Additionally, PG&E’s constraints study case where no charging is allowed from 4-9 pm was agreed upon as one test case, while other modeling cases include ones where the RTE is and is not enforced. The use of a close-to-real-time GHG signal was another test case modeled by SGIP parties.

CESA has prepared a potential path forward using the information from the study efforts and findings. CESA plans to propose multiple ‘pathways’ given that many energy storage projects are configured differently and thus have different customer needs, cycling plans, and energy durations that are more versatile and effective than a one-size-fits-all approach to ensure that the program’s rules are met. Each of the proposed pathways assume that qualifying energy storage systems can achieve a ‘spec-sheet’ roundtrip efficiency of 67.5% and can either be applied to individual projects or be applied on a fleet-wide basis for each developer. Specifically, CESA proposes the following pathways:

• Existing Pathway: For some systems, the existing rules reasonably direct resource behavior to achieve GHG savings and other program goals.

• Deemed Compliance Pathway: For some smaller systems, ongoing GHG tracking and compliance can be burdensome, so such resources could be deemed compliant if they take one or more of the pre-defined compliance actions, including: (1) compliance with solar PV ITC requirements; (2) operations according to new retail rate designs implemented in 2018 or some other approved rate (e.g., EV-A); and (3) participation in the CAISO ‘load shift’ product or some other eligible program that directs storage system charging or discharging to periods of grid needs

• Modified PBI Approaches: While the PBI approach provides an important incentive for system utilization, the approach is not well-designed for systems serving customers with less regular cycling needs or goals, so CESA proposed the following modified PBI approaches: (1) modified PBI with regular cycling where resources that cycle often (e.g., permanent load shifting applications) can take this option to cycle at minimum 104 times per year, not be subject to RTE requirements, and be evaluated for its charge, discharge, and parasitic losses based on system average emissions, rather than marginal emissions; and (2) modified PBI with irregular cycling where resources that typically await unique economic opportunities to cycle and are differently configured from ‘deep cycling’ resources should not have RTE requirements but should be evaluated for GHG effects based on marginal emissions for its cycling (while parasitic loads should be evaluated based on average emissions)

CESA also proposed multiple compliance actions that could be used by the PAs if resources do not achieve GHG reductions. First, CESA proposed the GHG allowance purchases and retirement option where systems deemed out of compliance may purchase and document the retirement of GHG ‘cap and trade’ allowances commensurate to offset any GHG emissions from the applicable SGIP system or portfolio operations. Second, CESA proposed the PBI withholding option where PBI systems deemed out of compliance may elect to have some funds withheld from future PBI payments, with the amount of funds withheld equating to the cost of GHG allowances for the applicable amount of emissions at the prevailing GHG emissions allowance rate. The maximum amount withheld would be the full PBI payment.

On March 30, 2018, WattTime, the nonprofit organization that is developing the platform to deliver a marginal GHG signal, held a webinar on how companies can receive a GHG signal through an application program interface (API). In this webinar, WattTime walked through the technical capabilities of the platform in the context of SGIP requirements and discussed how it currently delivers a GHG signal to its current partners. The emissions from consuming electricity changes throughout each day, and is different from day to day, but WattTime stated that it makes data available in real-time every five minutes or as day-ahead every hour. Typically, companies using WattTime’s API can choose a shadow price per pound of carbon to their objective function, or can create an “indifference” window to receive a recommendation on the time to charge within a “preferred window” of time. WattTime observed that the former type of integration is what energy storage companies use. Additionally, WattTime has developed tools to forecast marginal emissions based on probabilistic forecasting at different time steps (e.g., four hours ahead, month ahead) as additional features for SGIP developers. To support our proposed GHG pathways above, CESA recommended that the tools to deliver this signal as well as the tools to provide free informational performance audits through an API end-point data assessment be funded through the program’s measurement and evaluation budget.

On April 17, 2018, the working group began discussion on GHG compliance pathways as well as measurement and enforcement mechanisms. CESA introduced some of our ideas here and stakeholders seemed to support optionality for SGIP developers, especially for PBI projects where the developer can determine the best path to GHG compliance given that ‘penalties’ or ‘awards’ may be assessed based on GHG performance. The PAs also appeared to support a ‘deemed compliant’ pathway for small residential energy storage projects. The key area of contention was around what to do with non-residential, non-PBI projects, which represent a significant number of projects in the program and were also attributed to relatively high GHG emissions. CESA raised the option of allowing for upfront deemed compliant pathways for these systems with enforcement through infractions, but PG&E appeared to want more ‘teeth’ in the enforcement mechanism. The working group moved toward a ‘90/10 approach’, where such systems would be able to receive 90% of their SGIP incentives upfront with 10% of the SGIP incentives paid out on a PBI basis over a three-year period based on GHG performance. This seems like a reasonable approach for such projects as it retains most of the SGIP incentive while providing some ability for the PAs to enforce (or reward) GHG performance.

Other key areas of discussion at this working group meeting was around whether to enforce GHG performance on a project-by-project basis or on a fleet-wide basis by developer. PG&E also indicated its desire to measure GHG performance on a quarterly basis, especially in the early days of these new rules, but recognized that GHG performance can vary by season and/or month. Additionally, the working group was split on whether to reward projects that reduce GHG emissions beyond the compliance requirements. Finally, the working group seemed to come to some consensus around getting SGIP projects to GHG neutral and potentially ‘raising the bar’ on GHG reductions over time.

On April 24, 2018, an extensive working group meeting was held where the aggregated and anonymized model results were presented, followed by a discussion on conclusions, recommendations, and proposals for the final report. CESA developed a document that laid out many of the considerations for how SGIP rules could evolve to support the program’s market transformation, grid support, and GHG emission reduction goals. CESA has used this document to guide working group discussions. The working group sought to identify program rules that are preferred and those that are “deal breakers”, reflected in rankings.

On May 8, 2018, a conference call was held that presented AESC’s revised analysis results. The aggregated results found that almost all project class and new (not old) rate combinations reduced GHG emissions when co-optimized with a GHG signal, with the other three solutions (cases) studied produced similar GHG emission reductions for most project class and rate combinations. The new TOU rates also generally had positive impacts on customer bill reductions and GHG emissions reductions for both standalone energy storage and solar-plus-storage systems. Additionally, every modeler found better GHG impacts on average for higher single-cycle roundtrip efficiency and found inconclusive evidence of GHG emissions impacts for the charge constraints case. Finally, with a few exceptions, many modelers found customer economics are not hurt by trying to achieve GHG emissions reductions.

On May 15, 2018, a working group meeting was held to discuss key operational, verification, and enforcement proposals, highlighting areas of consensus and non-consensus for each potential proposal. The working group agreed that the statutory requirements to reduce GHG emissions should be honored, preferably without sacrificing the other program goals. For reasons tied to legal and administrative burden and program sunset date in 2020, the working group also agreed that SGIP should avoid ex post incentive claw-backs, if possible, as well as complex programs changes that risk shutting down the program for a long period. Additionally, the working group agreed that the program should support optionality where feasible to allow multiple pathways to compliance, support more regular verification to check for compliance, and penalize poor performance via incentive reduction options. However, there were many areas of non-consensus in the working group. For example, the working group was still working through whether: fleet and/or project level compliance verification and enforcement is appropriate; whether legacy projects should be subject to similar compliance requirements; whether a carbon scheme should be implemented given its complexity; whether cycling and roundtrip efficiency requirements should remain; and whether non-residential, non-PBI projects should now be subject to some portion of their incentive as PBI payments. The drafting process for the final report was initiated by AESC based on guidance from the CPUC’s Energy Division.

On June 4, 2018, the final working group meeting was held. AESC, the working group facilitator, summarized the key takeaways from the modeling effort as follows:

• Residential systems under old rates consistently reduced GHG emissions when paired with solar and are shown to achieve greater GHG emissions reduction when utilizing and co-optimizing around a GHG signal.

• Residential systems under new rates almost always reduced GHG emissions when co-optimized around a GHG signal, regardless of whether they are paired with solar.

• Commercial systems under old rates reduced GHG emissions 82% of the time when performing GHG emissions co-optimization.

• Commercial systems under new rates and paired with solar reduced GHG emissions 85% of the time when co-optimized with the GHG signal (100% of the time when subject to the 85% single-cycle roundtrip efficiency).

• Commercial systems under new rates but without paired solar reduced GHG emissions 40% of the time when co-optimized with the GHG signal (44% of the time when subject to the 85% single-cycle roundtrip efficiency).

The working group also finalized a set of recommendations and options for new and legacy projects to ensure compliance with the program’s GHG goals. A fleet compliance mechanism is included in the draft report, where developers would be subject to evaluation and compliance for a portion of their fleet of energy storage systems for a period of five years. After five years, no projects would be subject to GHG emissions accounting for the purpose of compliance and enforcement. New PBI systems would be evaluated on an individual system basis for the duration of their PBI payments, but not less than the fleet evaluation period (10 years). For legacy PBI projects, measurement and verification will be done on a per-project basis until the end of the PBI period, after which it will be monitored for the remainder of the 10-year permanency and warranty period. The rationale of the fleet compliance mechanism is to allow high GHG-reducing projects to offset GHG-producing projects while maintaining the overall program goal of reducing GHG emissions and providing flexibility to developers to manage their fleet-wide GHG emissions. However, several parties opposed this proposal because many individual projects may be incentivized to not meet the GHG emissions standards of the program after the five-year PBI period. Also, stakeholders seemed to disagree on whether measurement and verification would still be needed after the five-year PBI period.

On September 6, 2018, a Ruling was issued that attached a GHG Signal Staff Proposal for party comment. Based on the recommendations from the GHG Signal Working Group Report, the Staff Proposal recommends several operational requirements and verification and enforcement mechanisms for SGIP-funded energy storage systems. Below, CESA summarized the key rules from our consensus agreement as compared to what is recommended in the Staff Proposal to identify ways the CPUC can consider a suite of changes. Note that many distinctions were made to new versus “legacy” systems.

CESA expressed support for the GHG emission reduction goals of the program. However, CESA emphasized that the energy storage industry needs workable incentive programs in order to develop this sector of the energy storage market and to achieve both customer, grid-support, and environmental goals. In addition, while the Staff Proposal makes a worthy attempt to address the GHG performance concerns of SGIP-funded energy storage systems, CESA recommended multiple modifications to the Staff Proposal that are needed. Importantly, the punishment must fit the crime, as the Staff Proposal’s consequences for GHG emissions appear extremely harsh and disproportionate and the GHG emission reduction goals are set higher than necessary. Other modifications and recommendations include the following:

• SGIP rule changes should strive to achieve the program’s goals while also being reasonably workable for industry and BTM energy storage developers so that SGIP funds are effectively deployed.

• The Staff Proposal’s consequences for underperformance on the GHG emissions reduction goals are excessive while the GHG emissions reduction goals are set higher than is reasonable.

• Multiple modifications to the Staff Proposal are needed.

• The capacity benefits of BTM energy storage systems (i.e., the “build margin”) should be valued at some point in the program’s review.

• The “praise list” is an unnecessary step and may be misleading and thus should not be pursued.

• A Revised Staff Proposal with an opportunity for further stakeholder comment and feedback should be added to the procedural schedule.

Twelve parties commented. The more ‘anti-SGIP’ parties, such as PAO (formerly the Office of Ratepayer Advocates), SDG&E, and SoCalGas, agree with the Staff Proposal and recommend more punitive measures for non-compliance or under-performance – e.g., higher percentages of PBI incentives withheld, permanent suspension of developers, project-specific compliance over fleet-level compliance, and reduced developer cap. CESA and all energy storage industry groups want GHG consequences on a per-ton basis, do not support the suspension consequences, and oppose retroactive ratemaking. Importantly, CESA and others sought to not discourage SGIP participation with overly prohibitive program designs. Broadly, PG&E and CSE take more middle-ground views, with PG&E wanting to start with a lower threshold (10 kg-CO2/kWh) and stricter exceedance bands over time, and with CSE supporting reduced PBI payments over penalties. Consideration of how SGIP interacts with DR is also raised as a “pathway” for compliance (PG&E) but could create double compensation issues (SCE). Finally, PG&E argued against delaying implementation of new operational requirements, while SDG&E favored pausing the program until new rules are adopted.

See CESA’s comments on September 26, 2018 and reply comments on October 5, 2018 on the GHG Staff Proposal

On October 22, 2018, a workshop on the Staff Proposal was be held to discuss relevant findings from the 2017 SGIP Storage Impact Evaluation Report, followed by facilitated discussion around different recommendations included in the Staff Proposal. CESA focused on the theme of how the energy storage industry supports GHG emission reductions and is open to SGIP reforms. However, CESA reminded the CPUC and stakeholders of the build-margin GHG benefits, how pathways to compliance are preferred, and how the penalty should fit the crime. CESA also emphasized the need to update tariffs and avoid overly limiting SGIP program participation, given the grid support and market transformation goals. CSE and WattTime also discussed how $/MT penalties are more suitable for optimization and easier to administer as opposed to an arbitrary threshold target, which may distort incentives for SGIP developers. Furthermore, Enel raised important data points on the challenges of achieving the CPUC’s threshold target, while WattTime discussed how simulation modeling results may be optimistic because it depends on perfect foresight into load forecasts and GHG signals. Finally, Stem highlighted how it is difficult to achieve arbitrary thresholds on a project-by-project basis due to the unique and different load shapes of customers, thus supporting a fleet-wide compliance pathway.

On December 31, 2018, a Ruling was issued that attached a Revised GHG Staff Proposal that provided some improvements, though some negative aspects of the proposal remained. For new projects, defined as those submitting applications after the “go live” date for new rules, staff recommends different rules for commercial (all nonresidential projects) and residential projects:

• New commercial projects: The CPUC staff proposes a PBI structure for all new commercial projects, such that 50% of the incentive is paid upfront and the remaining 50% is paid over five years. PAs would verify each project’s GHG reductions annually and, if the project is found to reduce GHGs less than 5 kg-CO2/kWh or increase GHGs, the PA would reduce the project’s annual incentive payment by $1/kg ($1,000/ton) of CO2 over the 5 kg/kWh reduction threshold. PAs would provide projects with semi-annual feedback on GHG performance. The RTE requirement would be eliminated.

• New residential projects: The CPUC staff proposes to eliminate the annual RTE requirement and require all new residential projects to enroll on an approved time-varying rate and have a single-cycle roundtrip efficiency (SCRTE) of at least 85%. Projects that meet these criteria would be deemed to reduce GHGs, and no annual GHG verification or enforcement would be required.

For legacy projects, defined as those submitting applications before the “go live” date for new rules, the CPUC staff proposes to eliminate the annual RTE requirement and instead require developer legacy fleets to reduce GHGs annually. PAs would leverage existing verification work performed by Itron through the annual impact evaluation process to identify non-compliant fleets, and use existing SGIP Handbook language to enforce the GHG requirement for developers whose legacy fleets are found to increase GHGs. PAs would focus their enforcement efforts on the highest emitters and give developers the chance to set and meet compliance plan milestones prior to issuing infractions. Residential customers with legacy systems who enroll on an approved time-varying rate would be exempt from enforcement.

In sum, the Revised Staff Proposal reduced the GHG target threshold but still had a ‘greater than zero’ target for new commercial projects, which CESA disputed as being inappropriate and unnecessary given statutory requirements to reduce GHG emissions by any amount. At the same time, the positive improvements to the Revised Staff Proposal for new commercial projects include the:

• Revised PBI split from 40% upfront and 60% PBI to a 50-50 split

• Reduced burden of data reporting and evaluation from semi-annual instead of quarterly GHG performance measurement

• Removal of the program suspension penalty for projects that have completed their 5-year PBI term and instead have non-compliant projects be subject to existing SGIP Handbook enforcement mechanisms

Similarly, for new residential projects, the Revised Staff Proposal proposes to lean more on “deemed” approaches, among other positive changes:

• Removal of additional verification and enforcement in favor of “deemed” pathways for projects on approved time-varying rates or with projects having 85% SCRTE or higher

• Requiring PAs to maintain a list of approved time-varying rates whose TOU periods align with grid emissions

• Removal of the requirement to pair energy storage with solar

Finally, for legacy projects, there were some positive changes but still some areas of concern and lack of clarification:

• Elimination of the RTE pathway and instead establish requirement for developer’s legacy fleets to reduce GHG emissions on an annual basis

• Exemption from enforcement for legacy residential customers who enroll on an approved time-varying rate

• Reduction of the 260 cycles/year requirement to 130 cycles/year for legacy commercial projects

• Use existing verification methods and Handbook infraction language to verify and enforce GHG reductions rather than a fleet compliance approach with automatic program suspensions

In addition to these changes, the Revised Staff Proposal would also direct the PAs to make an interim GHG signal available within five months of a CPUC decision, and a final GHG signal available within eight months of a CPUC decision, in order to give the PAs additional time for contracting and program participants additional time to integrate the signal into their operations. The “go live” date for new rules would also be postponed from four to eight months following a CPUC decision. The Ruling indicated that it aims to issue a PD on this matter in Q1 2019.

CESA supported the incremental improvements to the Revised Staff Proposal, such as the deemed pathway for new residential projects, but recommended some additional changes, specifically around the proposal for new commercial projects and legacy projects:

• The proposal to develop and publish a GHG signal should be adopted, potentially through a separate and expeditious decision.

• The 5 kg-CO2/kWh threshold for new commercial projects is inappropriate and should be revised to zero or some lower threshold that reflects real-world forecast uncertainty.

• The $1,000/ton penalty price is unreasonably high for new commercial projects and should instead be set at the cap-and-trade allowance price or at one of the Commission-approved values for GHG emissions.

• The proposed underperformance penalties for new commercial projects are harsh and should instead incentivize energy storage projects to outperform on goals in later years to ‘make up’ for underperformance in earlier years.

• The fleetwide enforcement approach for new commercial projects for Year 6-10 should be removed.

• Enforcement provisions after Year 10 should be clarified.

• While supportive of the deemed path, the proposal for new residential projects should also create a path for projects that deploy and install energy storage solutions with less than 85% SCRTE.

• Legacy projects have encouraged innovation and learning and should not be punished.

• Publication of developer performance could be misconstrued and misapplied and should be avoided.

• Additional deemed pathways for non-IOU residential projects should be developed through analytical criteria

• A comparable approach for evaluating GHG reduction progress to thermal energy storage projects should be applied.

Other parties also submitted comments, with the PAs generally in support of the Revised Straw Proposal. PG&E recommended immediate approval of the Revised Staff Proposal due to the possibility that the unsettled nature of SGIP GHG rules negatively affecting funding uptake. SCE and SDG&E recommended revisiting the threshold annually, while SDG&E and SoCalGas disagreed with exempting new residential projects from post-verification requirements. PAO also indicated they could live with a deemed approach for residential projects but recommended this approach to be reevaluated at a later time. Due to low uptake in the Equity Budget, GRID Alternatives also made a case for deemed compliance approaches and a menu of such approaches for all Equity Budget projects.

CESA sought to rebut opposing points and arguments. CESA explained that adding complexity to program administration and participation and establishing retroactive penalties will reduce participation and that the penalty and GHG threshold concepts lack sufficient analytical bases. CESA also highlighted how SCE’s dual participation issues are out of scope.

CESA’s comments and reply comments on January 22, 2019 and January 28, 2019 on the Revised Staff Proposal

On April 15, 2019, a Ruling was issued seeking comment on implementation of SB 700, which authorized the CPUC to extend annual collections for the program for five additional years, from December 31, 2019 to December 31, 2024, and extends administration of the program for five additional years, from January 1, 2021 to January 1, 2026. The Ruling sought feedback and responses on several program design areas. CESA supported key program modifications but added that the CPUC should view SGIP as a market transformation and technology deployment program and strive to avoid making program rules and processes overly complex, while still being a sophisticated program that effectively achieves its goals. CESA expressed concerns about setting prescriptive grid-support requirements when some pathways are not available or insufficiently available for SGIP systems. Instead, CESA recommended that the CPUC focus SGIP on market transformation and technology deployment, with compliance options for GHG and grid-support pathways.

Opening comments were filed by a number of parties. The context of these comments was changed with the issuance of the PD on GHG requirements. As a result, some of the questions around grid-services requirements or uncertainty about GHG requirements were now moot and addressed in many ways through the PD. However, CESA observed a number of areas for potential comment, especially as SDG&E and SoCalGas continued to criticize the program as being irreparably ineffective, while SCE focused on clarifying the meaning of SGIP incentives by proposing that incentive levels be tied to avoided cost values in the Avoided Cost Calculator, which is used in other programs to measure cost-effectiveness. In response, CESA commented on the need to view the responses to the Ruling within the context of the GHG PD as well as within the historical context of the program’s evolution, since we noticed several ideas that were being resurfaced despite being rejected by the CPUC in the past. Specifically, CESA commented that SGIP is a technology incentive program and should not be framed as or modified to become a grid services program and that energy storage systems should not be held accountable for poor rate design and the focus should instead be on improving rate designs.

See CESA’s comments on May 30, 2019 and reply comments on July 12, 2019 on the Ruling

On May 31, 2019, a PD was issued that proposed to modify operational requirements to ensure that eligible SGIP energy storage systems, including thermal energy storage systems, reduce GHG emissions. The PD made incremental improvements on the CPUC staff proposal, particularly around the treatment of legacy projects, but appeared to still have some problematic elements, based on CESA staff's review:

• The PD maintained the 5 kg-CO2/kWh threshold for new commercial projects as a modest goal, despite CESA's arguments that a 0 kg-CO2/kWh threshold is reasonable and meets the statutory requirements. The PD included commentary on how the 5 kg goal aligns with the SGIP program goal for market transformation. For similar reasons, the PD proposed to use the one-hour-ahead GHG signal for GHG measurement and compliance purposes. This is an area that CESA may need to comment on - i.e., how market transformation goals are being defined by the CPUC, where the broader goal of deployment may be overly de-prioritized, in the context of the SB 700 Ruling questions and comments.

• The major change was around making all commercial projects, regardless of size, subject to 50-50 upfront and PBI payments, which may raise challenges to the financeability of small commercial projects, especially with the new GHG threshold and penalty structure being proposed.

• The PD made positive developments around removing the annual RTE requirement for new systems and provided options and relaxed GHG requirements for legacy systems.

• The PD was positive in that it maintained the deemed-compliant pathways for new residential systems, but it was also negative in regards to how it maintained the shame/praise list idea, which the PD justified on the basis of the lack of enforcement tools for certain cases (i.e., legacy, new residential projects, post-PBI period).

There were intersections of this PD with the questions posed in the SB 700 Ruling, such as around resiliency and backup power, which has GHG implications and can impact the GHG profile and operations of SGIP systems as they appear in compliance and performance evaluations.

CESA recommended several modifications to the operational and GHG requirements proposed for adoption in the PD that ensures continued growth of BTM energy storage deployments while ensuring achievable and necessary grid support and GHG emission reductions.

• CESA discussed how the definition for “new” versus “legacy” projects is reasonable but the definition of “developer fleet” should be modified and defined differently for residential versus non-residential projects to reflect average project size.

• CESA expressed our support for the one-hour-ahead GHG signal for GHG compliance but recommended that the CPUC not penalize and maybe should incentivize projects to use the real-time signal.

A number of other parties also submitted comments:

• PG&E sought clarification on “application submitted” as the threshold for new versus legacy projects while SDG&E recommended that new operational requirements take effect once the final GHG signal is implemented.

• The PAs requested flexibility to extend timelines given the significant time it might take to craft and issue a solicitation and then to select a vendor. For the non-CAISO areas (e.g., LADWP), WattTime suggested that it can implement a low-cost proxy method using ‘nearest’ CAISO price nodes to generate a GHG signal – an idea that PG&E and CSE supported – and recommended the use of a “benchmark optimization” to determine the accuracy of the GHG signal for all areas. In addition, PG&E, CSE, and WattTime expressed concern about the different metrics used for compliance versus evaluation of GHG emissions and how the GHG signal vendor should only be responsible for marginal emission data and signals, not also the platform to upload performance data, to reduce administrative costs. Tesla added that the GHG signal should be made available via an API to ensure digital accessibility for developers and CALSSA recommended an automated portal for data submittal.

CESA subsequently rebutted points made by SDG&E and SoCalGas. CESA reiterated that the PD’s proposed cut-off date provides market certainty and how the one-hour-ahead signal should be used for compliance given multi-optimization around different objectives of storage systems but noted that framing of the results should be done carefully and clearly.

See CESA’s comments on June 20, 2019 and reply comments on June 25, 2019 on the Proposed Decision

On August 9, 2019, D.19-08-001 was issued where several key changes were made that are highlighted below. CESA also highlighted key areas of no change despite our comments to make the necessary modifications:

• New Residential Projects: No changes were made to remove the required 1.69 peak-to-off-peak differential to determine eligible deemed-compliant rates for residential storage customers or to allow for solar-only charging or solar self-consumption mode as deemed-compliant pathways for residential storage customers. The decision pointed to the working group report that modeled solar-only charging and solar self-consumption mode on TOU rates showing greater assurances of GHG emission reductions as compared to those that were on “non-economic” rates. This is a key area of non-change that is likely limiting to residential storage developers. Given the other performance incentives and penalties in place, the limited set of eligible rates by maintaining the rate differential requirement is unnecessary for achieving GHG compliance.

• Eligible Residential Rates: Several EV rates (i.e., PG&E’s Residential EV-B Rate, SCE’s TOU-EV-1 Rate, and SDG&E’s EV-TOU, Residential EV-TOU-2-, and EV-TOU-5 rates) were added to the SGIP-approved list of eligible deemed-compliant rates for residential storage customers, convinced that these rates meet the required rate differential. However, customers on CARE rates (the applicable rate for qualifying low-income customers) are allowed to enroll in any time-varying rate, as not all IOU customers have TOU rates with the required 1.69 peak-to-off-peak differentials, though the decision recommends that the IOU work to develop such CARE rates with the required differentials.

• GHG Signal for Compliance: Compliance will now be measured against a five-minute-ahead GHG signal as opposed to a one-hour-ahead GHG signal given the greater accuracy of and consistency in performance-related messaging for the former and because this was the GHG Signal Working Group’s consensus recommendation. This change represents one of the drastic changes in the decision, where compliance will now be measured a more accurate but stricter signal that may be difficult for developers to reasonably respond to, given other services and use cases being pursued by BTM storage projects.

• Commercial Legacy Projects: The annual cycling requirement is maintained for all three options (130 cycles) but the roundtrip efficiency (RTE) requirement is removed for Option 2; the decision also clarified that Option 2 allows for compliance through an economic DR program enrollment. The CPUC was persuaded that enrollment in a DR program represents a reasonable trade-off to relaxing the RTE requirement. In CESA’s assessment, the decision was positively modified for removing the RTE requirement but unfortunately maintained the annual cycling requirement at 130 cycles instead of our recommended 52 cycles.

• GHG Performance Verification & Penalties: Verification will be done through an annual SGIP impact evaluation sampling procedure as opposed to once every six months. The CPUC was persuaded by arguments to reduce the PA’s administrative burden and to account for the lack of wireless communications from Equity customers. However, the decision was modified to allow the PAs to penalize developers via infractions, suspensions, or more frequent data collection and monitoring (back to every six months) who do not submit data in a timely fashion or perform poorly under this more ‘relaxed’ evaluation requirement. Generally, the reduced reporting burden is a positive development for both PAs and developers.

• GHG Performance Reporting & Post-PBI Enforcement: The ‘praise/shame list’ is maintained but the decision clarified that the SGIP evaluator should work with CPUC staff to ensure that this information is appropriately framed and contextualized. The decision also maintained the post-PBI data submission requirement to align with SGIP’s ten-year permanency period and clarified that SGIP Handbook tools should be used to enforce compliance (i.e., infractions, suspensions). CESA’s comments in this area were incorporated to a small degree with some assurances that the performance data will be contextualized, but the post-PBI data submission requirement was maintained despite issues we raised around the difficulty in implementation.

• GHG Signal Vendor: The contracted vendor is authorized to provide a marginal GHG emissions signal using the same methodology for non-CAISO regions as for CAISO areas, using the closest representative input data. The GHG signal vendor is directed to use the existing online SGIP data upload portal as opposed to a separately developed platform for developers to access their performance data. These are generally positive developments that ensure timely delivery of the GHG signal and avoid duplicative platforms for data submission.

• New and legacy project definitions: The decision clarified that the cut-off for new versus legacy projects will be based on the application submission date, not the incentive claim form date.

• Thermal storage: The decision clarified that measurement, verification, and performance evaluation approaches may need to be different for thermal storage projects, which should be addressed via a TES Working Group to convene with 60 days of the decision (September 30). In particular, the decision clarified that pathways for thermal storage systems with less than 85% single-cycle RTE should be explored, but a factual basis is needed to ensure that thermal storage projects also meet the 5 kg-CO2/kWh threshold applicable to all other storage projects. CESA will work with members who are thermal storage developers to begin work in this area.

The decision took effect immediately upon approval. The Commissioners discussed at the August 1, 2019 CPUC voting meeting about how this decision was based on the best technical data and analysis available to date. Despite some parties requesting an alternative for solar self-consumption, the Commissioners discussed how there is no data showing that this pathway will likely reduce GHG emissions and how new solar customers need to enroll in TOU rates anyway – i.e., bill impacts for grandfathered NEM customers will be mitigated by storage additions.

On November 27, 2019, the PAs submitted a joint advice letter implementing the GHG requirements adopted in D.19-08-001, which differentiated these  requirements and compliance pathways based on residential versus commercial and legacy versus new energy storage projects. Many of the implementation details as reflected in the SGIP Handbook are compliant with D.19-08-001, considering many of the revisions transpose specific guidelines, requirements, and language from the decision.

CESA indicated our support for the expeditious approval of the GHG requirements to provide program certainty to applicants and developers and to support the implementation of other major revisions of the program (e.g., Equity Resiliency Budget implementation). In particular, as noted in the Joint PA Advice Letter, CESA sought on-time availability of the interim and final GHG signal to support developer familiarity with the new GHG compliance signal. However, CESA offered certain areas that require additional clarification to support SGIP applicants and developers in navigating and understanding the GHG requirements of the program (as shown below):

• The PAs should provide explicit clarifications on eligible “economic demand response programs” in the SGIP Handbook for legacy commercial projects choosing the Option 2 compliance pathway. In response, the PAs clarified that tariffs can qualify as programs but that the DR resources must be integrated as a supply resource in the CAISO market. The list of eligible programs will be provided on the website as opposed to the Handbook for flexibility.

• The PAs should identify the eligible rates for new residential projects deployed at eligible municipal customer sites. In response, the PAs explained that municipal utilities are not obligated to engage with SGIP or the PAs, making it more feasible for customers to substantiate the eligibility of specific rates.

• The PAs should clarify the GHG requirements of multi-family projects and subject them to the GHG requirements for new commercial projects. In response, the PAs said that they will address VNEM arrangements in their forthcoming advice letter on February 18, 2020.

• The PAs should clarify the required documentation for verifying solar-only charging and solar self-consumption manufacturer-certified settings. In response, the PAs indicated that they will provide a template document in the near future.

• The PAs should offer a potential cure or grace process for the biannual data submission requirement for residential storage developers flagged for additional monitoring. In response, the PAs acknowledge this recommendation but found it unnecessary to propose such a process given the limited guidance from the decision on this matter.

• The lack of proposed methodology or modifications for the GHG requirements for large thermal energy storage systems is not compliant with D.19-08-001 and should be addressed in a Supplemental Advice Letter. In response, the PAs said that the decision did not direct a methodology and found that alternative methodologies should be addressed in a separate regulatory filing.

In their response, the PAs clarified that non-residential projects may begin their post-PBI monitoring period if developers receive all of their PBI payments before their fifth year of operations. This was an area of some ambiguity that CESA opted to not raise in our response, but this clarification is helpful and supports the continuance of existing rules that encourage greater cycling.

See CESA’s response on December 17, 2019 on the Joint Advice Letter

On February 24, 2020, the GHG signal implementation advice letters were “disposed” and approved, becoming effective on the same date. Given that the PAs generally addressed most protests and responses from parties in supplemental filings, the CPUC approved all aspects of the GHG signal implementation since the PAs have discretion to implement details that are not reflected in a CPUC decision (D.19-08-001). However, the one exception is that the CPUC found the PAs to be deficient for not approving an incentive calculation methodology for large thermal energy storage (LTES) systems. As a result, the CPUC directed the PAs to submit a joint advice letter within 30 days (March 25, 2020). This was great news for unlocking LTES participation in SGIP.

On April 15, 2020, PAs submitted a joint advice letter that proposed revisions to the SGIP Handbook to address the remaining orders in the SB 700 decision (D.20-01-021), including funding collections and allocations for the different budget categories and for PA administrative expenses. There was a hold-over item from the GHG requirements implementation advice letter that was previously unaddressed but are clarified in this advice letter. The PAs described two use cases to address the complexities with multi-family properties in SGIP.

• VNEM paired storage (Use Case 1): For IFOM storage paired with and solely charge from the VNEM generation facility, the GHG requirements will be determined based on the “primary use” of the storage, where it is subject to residential deemed compliance pathways (i.e., enroll in SGIP-approved rate) if 51% or greater of the VNEM credits is credited to tenant accounts. If the majority of the VNEM credits go to common load, the applicable requirements will depend on whether the common meter is on a commercial or residential rate.

• BTM storage (Use Case 2): For BTM storage that may serve tenant and/or common load while not being interconnected under the VNEM tariff, the applicant will be required to identify and substantiate with supporting documentation the “primary use” of the storage. If the primary use is for tenant load, the project will be required to be enrolled in an eligible TOU rate pursuant to residential requirements. If the primary use is for common load, the project will be subject to either residential or C&I requirements depending on the rate that the common meter is on.

On June 5, 2020, the PAs submitted a supplemental advice letter that made a number of changes in response to parties’ protests, but the PAs affirmed the establishment of waitlists to adhere to the residential soft target and affirmed its multi-family GHG rules to determine rules based on rate class as being easier to understand and implement, thus rejecting CALSSA’s recommendation. These changes were subsequently approved several weeks later.

GHG Compliant Rates

On March 11, 2020, PG&E submitted a Petition for Modification (PFM) to modify the GHG decision, D.19-08-001 to permit medical baseline (MB) customers to enroll in SGIP by enrolling in any MB TOU rate where no SGIP-approved MB TOU rate is available, consistent with the treatment of low-income (CARE) customers.

See CESA’s response on March 26, 2020 on the Petition for Modification

On March 18, 2020, SCE submitted an advice letter seeking to add Schedule TOU-D-5-8PM as an eligible rate for residential SGIP customers to enroll into to be deemed compliance with the program’s GHG requirements. With summer on-peak rate of $0.46/kWh and summer off-peak rate of 0.23/kWh, the rate would exceed the 1.69 differential requirement (2.0 ratio) to be an eligible rate for residential SGIP customers. This rate will be available for enrollment to determine upfront SGIP eligibility by April 17, 2020.

On June 5, 2020, D.20-05-041 was issued that approved PG&E’s PFM to modify D.19-08-001 to permit MB customers to participate in SGIP by enrolling in any TOU rate where no SGIP-approved MB TOU rate is available (i.e., one with a 1.69 peak-to-off-peak differential ratio), consistent with the treatment of CARE customers. The decision agreed that MB customers should not have to forgo the cost savings of MB to participate in SGIP and affirmed that such customers are prohibited from enrolling in TOU bill protection mechanisms to ensure alignment with GHG-reducing goals. The decision was also revised to require develop an SGIP-approved TOU rate for MB customers as expeditiously as possible.

SGIP Renewable Generation

Incentive Structure

On January 27, 2020, D.20-01-021 was issued that increased the base renewable generation technology incentive to $2/W with no step-down structure, with $5 million per project cap in recognition of the GHG emissions reduction and higher incentive needed to cover increased cost of renewable biofuels, though the directed biogas requirement is maintained. Furthermore, the decision adopted a $2.50/W resiliency incentive adder to support prioritized outreach to customers with critical resiliency needs, which helps cover the general economic need while prioritizing PSPS customers.

Zero Emission Fuel Blending Requirements

D.16-06-055 established a 10% minimum blending requirement for natural gas fueled generators starting in 2017, with the requirement ratcheting up annually thereafter - 25% in 2018, 50% in 2019, and 100% in 2020.

On October 21, 2016, the PAs filed their Advice Letter implementing that all gas-generation technologies are required to blend a minimum percentage of renewable fuel. At the same time, all natural gas-generation projects are required to meet the GHG emissions factor adopted in D.15-11-027 without the inclusion of biogas in the calculation of emissions. As long as the minimum blending requirement is met, blended fuel projects will receive a $0.60/W incentive for the percentage of renewable fuel used.

Like with energy storage, generation projects receiving SGIP incentives are subject to performance requirements. For projects less than 30 kW, the full $0.60/W adder is paid. For projects larger than 30 kW, 50% of the payment will be received upon projects completion while the other 50% will be paid through five years as a Performance-Based Incentive (PBI). Annual payments will be made after renewable fuel use data verification - i.e., the Renewable Fuel Use Report (RFUR).

SGIP Resiliency

Background

On April 15, 2019, Ruling was issued seeking comment on implementation of SB 700, which authorized the CPUC to extend annual collections for the program for five additional years, from December 31, 2019 to December 31, 2024, and extends administration of the program for five additional years, from January 1, 2021 to January 1, 2026. The Ruling sought feedback and responses on several program design areas. CESA supported the use of SGIP funds to direct SGIP projects for resiliency purposes by establishing a 20% Resiliency Adder to the incentive rate for eligible customers in High-Fire Risk zones, with demonstrated capability to do resiliency, and with certain exemptions to SGIP operational requirements.

See CESA’s comments on May 30, 2019 and reply comments on July 12, 2019 on the Ruling

Equity Resiliency Budget

On August, 9, 2019, a PD was issued that focused on modifications to jump-start the Equity Budget, which has seen virtually no participation. To address these barriers, the PD proposed to modify Equity Budget eligibility rules to become more broadly available, to increase the incentive rate to address how poor economics is the main barrier, and to take advantage of synergies with low-income solar programs, among other changes. No decisions were made on funding collections and allocations for 2020-2024 as authorized by SB 700, with the proposed changes mostly involving a shifting and carve-outs using already authorized funds collected through 2019, though we should expect some backlash from companies interested in preserving Generation Budget funds (e.g., fuel cell companies).

CESA generally supported the increased Equity incentive rate, the new Equity Resiliency Budget category along with a higher Equity Resiliency incentive rate, and the modifications to the incentive rate step-down structure based on energy duration but believed that these specific changes should be modified to varying degrees.  The CPUC was well-intentioned in proposing these changes but CESA recommended that the Equity and Equity Resiliency incentive rates should be set higher to initially cover 100% of eligible project costs, longer durations should be incentivized at higher rates given some of the misunderstandings of long-duration storage technologies, and cycling and GHG requirement implications should be reconsidered for the resiliency use case.  Furthermore, while the near-term focus of this PD is focused on Equity Budget changes, CESA recommended that the Commission also consider changes to General Budget projects that support resiliency applications as well as longer-duration technologies.

Many other parties submitted comments on the PD with most parties expressing support for the changes to the Equity Budget and the establishment of the Equity Resiliency Budget; however, some parties expressed concern with the viability of energy storage to provide resiliency in certain cases while others protested the transfer of funds from the Generation Budget to the Equity Resiliency Budget. In response, CESA supported higher Equity incentive rates and broader eligibility for the Equity Resiliency Budget but also rebutted parties’ comments opposing fund transfer from the Generation Budget to the Equity Resiliency Budget, HPWH eligibility, and additional processes to validate islanding. Finally, CESA recommended that disclosure language around energy storage capabilities should be provided to customers needing resiliency for critical medical equipment.

See CESA’s comments on August 29, 2019 and reply comments on September 3, 2019 on the Proposed Decision

On September 18, 2019, D.19-09-027 was issued that established a new $100-million Equity Resiliency Budget category with a higher base incentive rate ($1.00/Wh) was established to target customers who have least ability to fund storage system and critical facilities who serve Equity-eligible customers. Funding for the Equity Resiliency Budget will come from the accumulated unused generation budget. To support these resiliency applications for Equity projects, the decision modified the incentive rate step-down based on duration to be 100% for hours 2-4 and 50% for hours 4-6 to support Equity and Equity Resiliency customer needs. Eligible storage systems must be inspected and approved to be able to island by local authorities having jurisdiction (AHJs) and SGIP applicants must submit attestations to their ability to provide battery service during outages. The decision warned that developers should not increase price of system because of these higher incentives and maintained that operational and GHG requirements would still apply.

Compared to the PD, the decision made a number of positive changes responsive to CESA’s comments, including:

• Removal of potential intent language in SB 700 decision: The decision previously suggested that an additional $100 million replenishment will be directed to the Equity Resiliency Budget, but the removal of this language may suggest that the new funding allocation will be broader than just that budget category.

• Expansion of Equity Resiliency Budget eligibility to customers in Tier 2 High-Fire Threat Districts (HFTDs): The decision also added 911 call centers as eligible.

• Increase in Equity and Equity Resiliency incentive rates: The decision revised the Equity Resiliency (and the SJV pilot) incentive rate from $0.85/Wh in the PD to $1.00/Wh in the final decision to address the primary barrier to participation being lack of access to financing or capital. The PAs will have authority via a Tier 3 Advice Letter to modify any of these rates. The decision clarified that a developer cap does not apply to the Equity Resiliency Budget.

• Increase in incentive for discharge duration of 4 to 6 hours: The decision increased the incentive from 25% of base incentive to 50% of base incentive due to the benefit it can provide in addressing system ramping.

• Additions to the application form around resiliency: The decision responded to the IOUs concerns around ensuring that developers substantiate their project capabilities in “less-than-favorable” conditions during resiliency events to the PAs and provide this information with signed attestations to the customer. This addressed the disclosure concern.

• Affirming budget transfer from Generation Budget to Equity Resiliency Budget: No changes were made in this regard, though the decision recognized the comments made by the fuel cell and gas parties around resiliency potential from generation projects and added that this issue could be addressed in the SB 700 decision.

• Deferral on defining Equity Resiliency Budget eligibility based on PSPS Zones: The CCAs raised this point about how de-energization risk is tied to these “PSPS Zones” that may not entirely line up with the CALFIRE’s fire zone tiers, but the decision commented that these zones have not yet been well-defined, thus deferring on using such definitions for eligibility.

While the above changes or affirmations are positive and in line with CESA’s recommendation and comments, the decision also deferred on defining Equity Resiliency Budget eligibility based on PSPS Zones until they are more well-defined and increasing the system sizing incentive structure to a future decision. In sum, CESA landed favorably on many of these changes and was able to defend certain problematic comments from other parties. If the GHG requirements are implemented before January 2020, the CPUC has given the PAs authority to launch the modified Equity Budget and new Equity Resiliency Budget categories as early as January 1, 2020 but no later than April 1, 2020.

On December 3, 2019, the PAs submitted a letter requesting that they be able to submit two separate advice letters, with the first letter being submitted on December 17, 2019 to focus on covering all the requirements necessary to accelerate the opening of the Equity Resiliency Budget for residential customers and a second letter to be submitted 60 days later on February 18, 2020 to focus on covering all other requirements ordered in D.19-09-027. While recognizing the tremendous efforts of the PAs to implement many recent revisions of SGIP adopted over the past year, CESA was concerned with the requested 60-day delay of submission of non-residential implementation details, which would effectively delay the program requirements and the availability of Equity Resiliency Budget incentive funds for non-residential customers. As a result of the requested delay, CESA estimateed that the Equity Resiliency budget incentive funds will not be available to eligible non-residential customers by June or July 2020 at earliest, leading to resiliency-focused energy storage projects from being unable to be deployed in time for the next 2020 wildfire season.

CESA recommended that the CPUC direct the PAs to launch the Equity Resiliency Budget category for all eligible customers, including non-residential customers, by April 1, 2020 – the directed timeline in D.19-09-027. Not only would this launch date be compliant with D.19-09-027, but it would ensure non-residential customers would have an opportunity to address their resiliency needs. However, CESA recommended that the CPUC also direct the PAs to include key clarifications and implementation details related to customer eligibility, existing project eligibility, applicability of certain existing program structures, and documentation requirements in their December 17, 2019 Advice Letter rather than delaying these aspects of D.19-09-027 to the February 18, 2020 Supplemental Advice Letter.

See CESA’s letter on December 12, 2019 to the CPUC Executive Director

The CPUC Executive Director granted the PAs’ request for extension, finding it reasonable to take a phased approach to allow for small residential customers to benefit from the Equity Resiliency Budget as soon as possible while also agreeing that the full Equity Resiliency Budget shall be open no later than April 1, 2020, with clarifications provided in January workshops prior to second advice letter submission.

On December 11, 2019, a PD was issued that proposed to authorize ratepayer collections of $166 million annually for the years 2020 to 2024, pursuant to SB 700, and to prioritize allocation to customers affected by PSPS events or located in areas of extreme or elevated wildfire risk, pursuant to AB 1144. Out of the fully authorized collections, energy storage technologies will receive 85% of funds, up from 80% in previous funding allocation decisions (i.e., see AB 1637 decision). To provide some funding certainty for some time, the PAs would be authorized to submit advice letters to transfer funds between energy storage and generation incentive budgets subsequent to December 31, 2023. The 10% and 7% administrative budgets were approved for CSE and SoCalGas, respectively, while PG&E and SCE must use accumulated unused administrative funds, thus ensuring that most of the collections go toward incentive funding. The following allocations were proposed for adoption:

For the Equity Resiliency Budget, the PD proposed to maintain the Equity incentive rate ($0.85/Wh) and Equity Resiliency incentive rate ($1.00/Wh) with no step-down structure but expanded eligibility to include residential and non-residential customers “whose electricity was shut off during two or more discrete PSPS events prior to the date of application for SGIP incentives”. The October 2019 PSPS events provided new information to support updating eligibility criteria (e.g., lists are available from IOUs), but PD declined to determine this by “PSPS zone” that has yet to be defined. In either case, the customers must be otherwise eligible for Equity Resiliency – e.g., critical facilities for non-residential customers. The PD also defined additional customers as having critical resiliency needs:

• Markets (groceries, supermarkets, corner stores) are added as non-residential customers if they are a small business ($15M or less in last three tax years) – allows purchase of necessities and find air-conditioned space

• Households relying on electric-pump water wells are added as customers to address drinking water, sanitation, and fire-response needs (does not define as residential but presumably so)

• Independent living centers are added as non-residential customers to support individuals with disabilities (uses 29 U.S. Code § 796a definition)

• Food banks (soup kitchens, hunger relief centers, food pantries) are added as non-residential customers to ensure essential food sources for lower-income families (uses U.S. Code § 7501 definition)

As next steps, the PD proposed to accelerate the effective date for implementation of the GHG emission reduction requirements and acceptance of applications for small-scale equity resiliency residential projects to no later than March 1, 2020 since the scale and scope of the October PSPS events warranted this change. Through this is slightly later than the PAs’ proposed timeline, the PD does ensure a “backstop” effective date to get resiliency projects moving for small residential customers. Furthermore, to support efficient deployment of funds, the PAs were directed to process incentive applications within 45 days of receipt, with priority toward Equity Resiliency Applications. The 97-day timeline from Large-Scale Storage application submission to incentive reservation is unacceptable for PSPS needs.

CESA supported some of the larger decisions in the PD but recommended several modifications to the PD to better ensure that SGIP funds are directed to most effectively and efficiently address customer resiliency needs ahead of the 2020 and 2021 wildfire seasons while supporting continued storage deployments generally to achieve the program’s multi-pronged objectives.

See CESA’s comments on January 3, 2019 on the Proposed Decision

Though many of the proposed modifications are well-intentioned and generally effective, CESA believed certain refinements are needed to improve program outcomes and ensure a meaningful amount of deployment, which requires a recognition of some of the on-field realities of deploying resilient systems. Specifically, CESA recommends the following to overcome the major barriers to project deployment:

• Cycling requirements for energy storage systems claiming the resiliency adder or Equity Resiliency incentive funds should be reduced to 52 cycles per year to support resiliency objectives given that new GHG rules and performance incentives are in place.

• Eligibility for the resiliency adder and the Equity Resiliency Budget should be modified to not only allow PSPS-affected customers but also allow customers in Tier 2 or Tier 3 High Fire Threat District (HFTD) zones.

• Schools should also be added as eligible non-residential customers for the resiliency adder and the Equity Resiliency Budget.

• System sizing rules should be revisited to support the deployment of proper resiliency projects.

• This decision should affirm the Equity Resiliency Budget launch date as being no later than April 1, 2020, which is open to interpretation in D.19-09-027.

On December 17, 2019, the PAs submitted their first advice letter addressing residential customer requirements for accessing Equity Resiliency Budget. It was a relatively straightforward adoption of D.19-09-027 requirements for:

Customer eligibility (HFTD, Indian Country, Equity, SASH, DAC-SASH), including necessary reservation letter (SASH, DAC-SASH) or proof of Indian Country qualification

• Step-down of incentive based on duration

• AHJ approval of plans to operate in island mode as well as AHJ inspection

• Copy of Customer Resiliency Attestation Form (Appendix C) for storage greater than 2 hours

• Elimination of developer cap for Equity and Equity Resiliency Budgets

• Initial ME&O Plan (Appendix D)

The Customer Resiliency Attestation Form was the only “new” aspect of implementation from decision, which is mostly qualitative and takes informational requirements from decision. While disappointed in the lack of early guidance on non-residential storage projects, it is encouraging to see that the CPUC is intent on opening the full Equity Resiliency Budget category to all eligible customers no later than April 1, 2020.

CESA found that many of the implementation details as reflected in the SGIP Handbook are compliant with D.19-09-027, considering many of the revisions transpose specific guidelines, requirements, and language from the decision, and supports the PAs’ efforts, particularly in expediting the implementation of the Equity Resiliency Budget requirements for small residential customers. CESA supported the timely approval of the Joint PA Advice Letter albeit with clear affirmation of the April 1, 2020 launch date of the full Equity Resiliency Budget, further clarifications of implementation details for non-residential projects to be included in the upcoming workshop, and our recommendations for how the ME&O plan can be enhanced. Meanwhile, CCAs submitted a response offering suggestions on how CCAs can be leveraged to coordinate local, targeted ME&O, while GRID Alternatives sought the reallocation of SGIP PA administrative funds to low-income solar PAs in order to take advantage of synergies between solar and storage programs.

See CESA’s response on January 6, 2020 to the Joint Advice Letter

On January 27, 2020, D.20-01-021 was issued that revised the PD as follows:

• System sizing rules: Sizing limitations based on inverter size for resiliency-related projects are removed, and full incentives for systems sized above peak load are allowed upon demonstration of need. However, since the details are complex, the PD deferred to the PAs to allow them to submit any additional revisions in the advice letters. The PD also clarified that electrical and critical load panel and wiring upgrade costs are allowable costs for resiliency projects.

• Customer eligibility: The revised PD directed the PAs to establish a working definition of “discrete PSPS event” but indicated that they may narrow the eligibility criteria in the future due to grid hardening and resiliency investments. For markets, the $15-million annual revenue criteria was clarified as applying to a single location. To support developers, the IOUs are directed to ensure a method of customer identification as well as a master list of all circuits that have experienced two or more PSPS events.

• Implementation timeline: A three-stage advice letter process has been added to ensure Equity Resiliency Budget launch for residential customers by March 1, 2020 and for non-residential customers by April 1, 2020: (1) supplemental advice letter within 12 days of decision adoption for residential customers; (2) advice letter by February 18, 2020 for non-residential customers; and (3) advice letter within 90 days of decision adoption for all other program revisions and budgets adopted in this decision.

Overall, the modifications were a mixed bag in the sense that, on the positive side, CESA was able to secure some key clarifications to the launch dates of the Equity Resiliency Budget, get modification to the developer cap rules that were somewhat in line with CESA’s recommendations, have system sizing rules modified to accommodate resiliency projects, and have the PAs be directed to support customer identification. However, many of the major recommendations around increasing the General Large Scale Storage Budget incentive rate and broadening customer eligibility criteria were unchanged. Meanwhile, funding allocation flexibility was only slightly improved, but it could be seen as becoming more prescriptive with the new “soft target” rules for general residential storage projects. Despite these changes, there may still be opportunity to fix some of these detailed issues through the implementation advice letter review process.

On January 28, 2020, a supplemental advice letter was submitted to implement specific elements from D.20-01-021 regarding the Equity Resiliency Budget for residential customers, including expanded eligibility to include those who rely on electric pump water wells for water supplies if they reside in Tier 2 or Tier 3 HFTD zones, or if their electricity was shut off during two or more discrete PSPS events prior to the date of application of SGIP incentives. The PAs also clarified that electrical and critical load panel and wiring upgrades are allowable costs to be covered by SGIP incentives. CESA generally supported the minor modifications to the program since the funding allocation implementation will be included in a Joint Tier 1 advice letter on April 15, 2020 and majority of other changes (e.g., system sizing, developer cap, General Budget changes) will be included in a Joint Tier 2 advice letter on April 15, 2020.

See CESA’s response on February 18, 2020 on the Supplemental Advice Letter

The CPUC subsequently approved the advice letters with the issuance of a non-standard disposition letter, which attached a matrix that helps to clarify the eligibility rules for residential customers. All other responses and protests submitted by CESA, CALSSA, and CCAs related to ME&O and eligibility questions were dismissed because they would be addressed in a subsequent advice letter.

On February 18, 2020, an advice letter was submitted to implement program changes related to the Equity Budget and Equity Resiliency Budget for non-residential customers, including new incentive structures, revised program requirements, new marketing, education, and outreach (ME&O) plan, and updated budget allocations from accumulated unused funds. The following specifics were adopted for revision and implementation in the SGIP Handbook:

• Applied $0.85/Wh incentive rate for residential and non-residential Equity customers and $1.00/Wh incentive rate for residential and non-residential Equity Resiliency customers, which does not differentiate the incentive rate for non-residential customers who claim the ITC (like it does for non-residential General storage projects)

• Clarified that property owner may be the host customer for multi-family buildings enrolled in VNEM tariff and interconnected as VNEM system

• Established system sizing limits for multi-family storage systems under a 5 kW per tenant assumption that is aggregated to set whole-building size cap, unless additional load justifications are provided to go above this cap

• Implemented non-residential customer eligibility criteria for Equity Resiliency Budget, which differentiates between customer and “community” related eligibility criteria and places burden of proof to non-residential customers to demonstrate “majority” of customers served are DAC or low-income customers

• Implemented “proof of coordination” requirement with local government and California Office of Emergency Services for non-residential projects claiming Equity Resiliency incentives or resiliency adder; otherwise, such projects will be deprioritized

• Implemented San Joaquin Pilot budget ($10 million), incentive design ($1.00/Wh), and eligibility (pilot host communities)

However, the PAs declined to modify the system sizing limit issue related to the storage application for resiliency. CESA argued that the sizing limit to the customer peak load should be removed for storage projects claiming Equity Resiliency Budget incentives or the resiliency adder, per the intent of D.20-01-021 and consistent with the flexibility afforded to the PAs in implementation. In addition, CESA extended the argument in that the sizing limit to the customer peak load should be removed for storage projects that do not qualify for Equity Resiliency Budget incentives or the resiliency adder but would still seek to size the storage system for resiliency needs. Furthermore, CESA commented that customer eligibility and identification should be easier to understand and more accessible, and ME&O efforts and materials should incorporate feedback and review from storage vendors. While not able to address in the advice letter process, CESA recommended that all Equity and general market energy storage projects with longer than two-hour discharge duration should not be required to demonstrate it can provide backup power. In addition, the incentive rate step-down structure by duration from D.19-09-027 should be extended to general market energy storage systems, as explained in D.20-01-021.

See CESA’s protest on March 9, 2020 on the Joint PA Advice Letter

The PAs agreed with the need to allow resiliency projects to receive incentives for a system that is sized above peak load due to modular component sizes to accommodate the customer’s peak load, subject to demonstration of this need. This change was later reflected in the PAs’ joint supplemental advice letter. However, the PAs found it an “unreasonable expansion” to remove sizing restrictions for all resiliency projects (e.g., General, Equity), not just Equity Resiliency projects; this merits a more holistic reevaluation. Finally, the PAs will provide additional clarification on GHG rules for multi-family energy storage systems in a supplemental advice letter.

On April 1, 2020, CALSSA submitted a petition for modification (PFM) to request several modifications, clarifications, and fixes to recent decisions issued to adopt and modify the Equity Resiliency Budget and other budget categories. The requests included:

• Clarification of the eligibility of all residential projects on tribal land: According to the language in the body of D.19-09-027, CALSSA highlighted how the CPUC intended to facilitate Equity Budget eligibility for residential projects on tribal lands by not imposing the same income requirements and resale or deed restrictions that apply throughout the rest of the state. However, this is unclear in the decision due to confusing and sometimes contradicting language.

• Correction of an error in the incentive step-down table: CALSSA highlighted a discrepancy between the body of D.20-01-021 and the table in Ordering Paragraph 26, where it should be corrected to what was discussed in the body.

• Removal of the back-up requirements for equity budget and general market systems with duration greater than 2 hours: CALSSA justified this changed based on the other non-resiliency applications, added costs associated with resiliency applications, and the lack of need for certain customers.

• Modification of the system sizing limits for general market energy storage systems designed to provide backup capability: The CPUC and PAs supported the system sizing limit exemption in cases where the modularity of system component sizes (e.g., inverters) made it difficult to size storage for resiliency, but in this PFM, CALSSA seeks to expand it to all projects seeking to provide resiliency.

• Automatic equity resiliency eligibility for homeless shelters, food banks, and independent living centers: These were relatively straightforward requests by CALSSA that reasonably supported resiliency for those in economic need or would be disproportionately vulnerable in a PSPS event.

CESA is aligned on all these requests and offered support. The response added further detail on the clarification requests while also finding it reasonable to make fixes to the resiliency requirement for all projects, which would only add cost for those not necessarily wanting resiliency.

See CESA’s response on May 1, 2020 to the Petition for Modification

Also in response, the IOUs and PAO opposed the changes to the resiliency requirement, finding the revisions to the duration-based incentive step-down structure as being intended to support resiliency projects, as well as the expanding the system sizing limits for general projects due to the impacts to other rules (e.g., NEM sizing restrictions) and the inability to fund additional projects.

On April 15, 2020, PAs submitted a joint advice letter that proposed revisions to the SGIP Handbook to address the remaining orders in the SB 700 decision (D.20-01-021), including funding collections and allocations for the different budget categories and for PA administrative expenses. CESA discussed how several of the implementation details are either be non-compliant with D.20-01-021 or lacking in sufficient clarity. Specifically, the “discrete PSPS event” definitions should be standardized and consistent where all customers in all applicable utility service territories are subject to the same definition as the one proposed by PG&E and SCE.

See CESA’s protest on May 5, 2020 on the PA Advice Letter

On June 5, 2020, the PAs submitted a supplemental advice letter that made a number of changes in response to parties’ protests. SDG&E modified their definition for SGIP purposes only to establish a single statewide definition, and deleted references to count PSPS events per calendar year, making it a cumulative criterion. SDG&E had previously defined “discrete PSPS event” as an event with 72 hours or more between concurrent weather events. When the definition is established for LADWP, the PAs agreed to set the definition for such customers as well. These changes were subsequently approved several weeks later.

On June 15, 2020, a PD was issued that granted some of the requests made by the CALSSA to fix, correct, or modify various aspects of the Equity Resiliency Budget decisions, D.19-09-027 and D.20-01-021. While  generally supportive of the PD, CESA recommended that the CPUC consider how confirmed reservations or waitlisted applications could fairly and efficiently modify their project applications given these changes to the incentive step-down rules for any Equity or General Market energy storage systems sized above two hours of duration. CESA aimed to ensure SGIP applicants have the ability to balance the certainty of funds rightfully claimed under the rules prior to the changes adopted in this PD with the ability to claim additional funds if available and reflecting the CPUC’s new rules adopted in the PD and in line with the waitlist rules and/or lottery priorities. In addition to those points, CESA made the following recommendations:

• Consistent income eligibility criteria should be established for customers located in and outside of Tribal Lands.

• A new finding should be added that addresses the need to investigate whether general-market commercial storage incentives are sufficient.

• The PAs should be directed to clarify and ensure that incentive sizing limits do not prohibit customers from installing larger storage systems.

See CESA’s comments on July 6, 2020 on the Proposed Decision

On July 21, 2020, D.20-07-015 was issued that made the following determinations:

• Indian Country eligibility: Residential customers in Indian Country do not need to reside in deed- or resale-restricted housing to be eligible for the Equity Budget. Instead, enrollment in or qualification for CARE rates. Likewise, the Energy Savings Assistance (ESA) Program will demonstrate eligibility for multi-family housing in Indian Country. The decision recognized that deed restrictions are generally absent in Indian Country, but this population has historically been neglected or suffered from poor electric reliability. Existing Equity applications will maintain their place in the queue and can instead demonstrate their eligibility per the modifications above.

• Expanded Equity Resiliency Budget eligibility: Food banks, homeless shelters, and independent living facilities are automatically deemed eligible for the Equity Resiliency Budget and are thus exempt in demonstrating that they serve at least one disadvantaged or low-income community since they inherently serve such communities. Location in Tier 2 or 3 HFTDs or experience with two or more PSPS events would still apply.

• Incentive rate step-down: An error was corrected to clarify that the full incentive rate (100%) is available for energy storage durations 0-4 hours and 50% of the applicable incentive rate for energy storage durations 4-6 hours, whereas D.20-01-021 had previously set the step-down at 50% for energy storage durations 4-6 hours.

• Resiliency requirement: Recognizing the costs associated with a universal resiliency requirement and non-resiliency-related benefits of storage greater than two hours of duration, Equity and General storage applicants will be allowed to choose to claim incentives under the legacy incentive step-down structure in order to not be subject to the resiliency requirement. D.16-06-055 set incentive rate step-downs as follows: 100% of full incentive for 0-2 hours; 50% for 2-4 hours; and 25% for 4-6 hours. In such cases, customers will need to be made aware that their systems do not have backup capabilities. The modified incentive rate step-down structure above, however, is still available for Equity and General customers seeking resiliency but do not qualify for the Equity Resiliency Budget. In making this determination, the decision affirmed the resiliency priority while continuing to advance SGIP’s other existing goals.

• General Large Scale Storage incentive rate: The decision rejected the request to modify the incentive rate, arguing that the uncertainty of GHG rules, not the insufficient incentive rate, is the main reason for the lack of uptake.

• System sizing limits: The PD rejected the request to allow projects not claiming Equity Resiliency incentives or resiliency adder to be sized greater than the customer’s peak load over the previous 12 months as necessitated by the modularity of system component sizes. In coming to this conclusion, the PD argued that oversizing is not needed for customers without critical resiliency needs and would lead to fewer projects being supported, with such projects claiming a larger portion of SGIP funds on a project-by-project basis.

The PD was thus revised to make the following changes:

• Indian Country eligibility: In response to comments, including from CESA, the PD was revised to establish consistent eligibility criteria for Equity customers in and outside of Indian Country, whereas previously the requirements were "stricter" for those in Indian Country. Specifically, the decision clarified that a single-family residence in Indian Country must demonstrate that household income does not exceed 80% of AMI, but unlike residential customers outside of Indian Country, resale and deed restrictions are not required for single-family and multi-family residences, respectively, since such restrictions do not exist in Indian Country.

• Resiliency requirement: The PD was revised to support CESA's recommendation to provide a one-time streamlined process to modify applications based on the changes made to make resiliency optional for greater than two-hour storage systems but subject to different incentive step-downs depending on whether resiliency is pursued. However, the revised PD stopped short of CESA's recommendation, instead deferring to the PAs (and CSE's concerns of implementation complexities) to propose a method in a Tier 2 advice letter to be filed within 30 days of the CPUC decision (around mid-August).

• System sizing limits: The revised PD added a finding to clarify that SGIP does not prohibit customers from oversizing energy storage installations but added a requirement for non-resiliency projects (i.e., those not claiming Equity Resiliency incentives or resiliency adder) that are sized greater than host customer's peak demand, even if the oversized incremental capacity is not supported through SGIP incentives, would need to be separately metered from SGIP-incentivized equipment.

The revised PD notably did not make a determination that an insufficient incentive rate is the main reason for the lack of uptake, as recommended by CESA. Notwithstanding that non-change, the other revisions represented positive outcomes that were mostly in line with CESA's recommendations in comments to the PD.

Resiliency Adder

On January 27, 2020, D.20-01-021 was issued that added a $0.15/Wh resiliency adder for non-Equity Large-Scale Storage projects where the adder is estimated to cover 50% of costs through Step 5 for non-residential projects, whereas no adder is needed for residential projects given market demand already and Equity incentives in place (which should be priority). The same eligibility requirements for the adder was in place other than for customers needing to meet the equity-related requirements. In lieu of a residential resiliency adder, the PD adopted 50% “soft target” for general Residential Storage Budget to be reflected in an evaluation. To meet the AB 1144 requirement, applications are required to notify local governments that they intend to or have installed onsite storage or renewable generation. For all General or Equity storage projects, the PD adopted a duration-based step-down structure as follows: 100% (0-4 hours), 50% (4-6 hours), and 0% (>6 hours). In doing so, the PD said it will encourage resiliency for all storage customers but reminded how they must still meet grid and GHG requirements.

PG&E Financial Assistance Pilot

On July 21, 2020, Resolution E-5086 was issued that only partially approved PG&E’s SGIP Financial Assistance Pilot. Specifically, 50% of the SGIP incentive upfront will be provided in the pilot once an eligible customer has an incentive officially reserved in the program. The goal of the pilot is to support projects that can be interconnected within 12 months, but in limited instances, unforeseen circumstances may arise that are beyond a developer’s control, where PG&E may exercise discretion on whether to recoup funds from developers if unable to meet the target 12-month timeline. The CPUC reasoned that this proposal balances the barriers for access by low-income residential customers with mitigating risk that contractors might submit “phantom projects” that never proceed to fruition. To ensure customer protections and address administrative efficiency, several determinations were made regarding the pilot:

• Through the participant agreement, PG&E will need to require contractors to legally affirm that they will not charge a residential SGIP host customer any out-of-pocket costs.

• Any contractor who is found to overcharge or prematurely charge customers must be permanently barred from further participation in the pilot.

• PG&E must make a determination on a contractor’s ability to participate in the pilot within 15 days of receiving a complete application.

• PG&E must file a report on the first of every month with Energy Division that provides the following information on each residential SGIP equity or equity resiliency project participating in the pilot.

However, due to the lack of detail, the Resolution rejected PG&E’s proposal to implement a revolving loan fund using on-bill finance for non-residential customers. This could be reconsidered upon PG&E putting forth additional information. In comments, PG&E continued to advocate for the on-bill financing mechanism but also reinforced the need to ensure protections against developers, while CALSSA pushed back against disallowing any project delays by developers.

SGIP Thermal Storage

Background

On April 15, 2019, a Ruling was issued seeking comment on implementation of SB 700, which authorized the CPUC to extend annual collections for the program for five additional years, from December 31, 2019 to December 31, 2024, and extends administration of the program for five additional years, from January 1, 2021 to January 1, 2026. The Ruling sought feedback and responses on several program design areas. CESA commented on how our recommended modifications to increase incentive levels by energy duration and to reform baseline calculation methodologies used for upfront and PBI payments would address thermal storage participation barriers.

See CESA’s comments on May 30, 2019 and reply comments on July 12, 2019 on the Ruling

On September 18, 2019, D.19-09-027 was issued that established two Equity Budget set-asides were established using funds transferred from the accumulated unused non-residential storage budget – i.e., $10 million for the San Joaquin Equity Budget and $4 million for the Equity Residential HPWH Budget. Workshop will be convened to identify and remove barriers to HPWH participation. Compared to the PD, the decision focused on the need to adapt the GHG requirements for HPWHs in the Thermal Storage Working Group and rejected arguments for its ineligibility. A HPWH workshop will be held some time in December 2019.

Large Thermal Energy Storage (LTES)

On September 13, 2019, a TES-focused workshop was held to discuss how the recently adopted GHG requirements (D.19-08-001) apply to thermal storage systems, including for heat pump water heaters (HPWHs), which gained eligibility in the program in a $4-million residential set-aside. With the GHG decision adopting a 5 kg-CO2/kWh annual GHG requirement as well as assessing compliance based on a 5-minute GHG signal, there were several questions raised around how different TES technologies could meet these new GHG requirements.

CESA supported the CPUC’s efforts and recommends that the program support optionality where appropriate and take different approaches for different TES technologies. For large TES technologies, CESA supported the adoption of the Trane and UC Davis methodology that measures real-time data and performance of storage and load shifting using dynamic baselines to calculate performance-based incentives and GHG emissions. At the same time, for small TES technologies, deemed methodologies may be more appropriate given the greater need for simplicity and administrative ease. Finally, for HPWHs, CESA recommended that the CPUC only incentivize HPWHs with grid-integrated controls, as default GHG benefits from switching to HPWHs constitutes an efficiency (not a storage) investment, while advocating for eligibility of controlled electric resistance water heaters (ERWHs).

See CESA’s informal comments on October 21, 2019 on the TES workshop

On February 24, 2020, the GHG signal implementation advice letters were “disposed” and approved, becoming effective on the same date. Given that the PAs generally addressed most protests and responses from parties in supplemental filings, the CPUC approved all aspects of the GHG signal implementation since the PAs have discretion to implement details that are not reflected in a CPUC decision (D.19-08-001). However, the one exception is that the CPUC found the PAs to be deficient for not approving an incentive calculation methodology for large thermal energy storage (LTES) systems. As a result, the CPUC directed the PAs to submit a joint advice letter within 30 days (March 25, 2020).

On June 2, 2020, after more than six months of delay to implement an incentive calculation methodology, the PAs submitted an advice letter rejecting the Trane/UC Davis dynamic calculation methodology due to its complexity and use of proprietary simulation models. Instead, the PAs and the SGIP Technical Working Group (TWG) developed a methodology based on the CEC’s Non-Residential Alternative Calculation Method Reference Manual to calculate the kW and kWh offsets for LTES technology under 1-in-10-year peak weather conditions. This methodology uses chiller curves approved by the CEC and used in the California Building Energy Compliance (CBEC) software for Title 24 compliance. The PAs supported this deemed-value approach because they argued that it is consistent and does not allow for over-estimation of the SGIP incentive.

CESA recommended that the CPUC reject this advice letter as failing to adopt a methodology for LTES that adheres to the GHG requirements and goals set for energy storage pursuant to D.19-08-001. In addition, CESA found the PAs’ assessment of the UC Davis dynamic methodology as being inadequate and rebutted the arguments made that such a methodology should be dismissed for being complex, resulting in an excessive incentive, creating an unreasonable administrative burden, and using proprietary simulation models. Specifically, CESA made the following points:

• The methodology based on the CEC Non-Residential Alternative Calculation Method Reference Manual is not compliant with D.19-08-001 in supporting LTES participation in SGIP.

• No explanation is offered on the purported overpayment of incentives under the UC Davis methodology, and SGIP Handbook rules are in place to cap costs.

• The use of proprietary simulation models is not a limiting factor for using dynamic methodologies.

• Arguments that the UC Davis methodology is too complex or represents an unreasonable administrative burden are unsubstantiated and can be streamlined through the use of .pdf outputs of ASHRAE-compliant models.

• Having different methodologies for LTES and small thermal energy storage (STES) is reasonable given the different costs and burden of monitoring.

See CESA’s protest on June 22, 2020 on the Joint PA Advice Letter

On June 25, 2020, the CPUC Energy Division suspended the advice letter for a period of up to 120 days (October 23, 2020) for further staff review.

HPWH Participation

On March 19, 2020, a workshop to address SGIP changes needed to accommodate HPWHs was held to discuss how to allow HPWHs to receive incentives under the statutory mandates of the SGIP to improve efficiency and reliability of the distribution and transmission system, and reduce emissions of GHGs, peak demand, and ratepayer costs. NRDC presented an overview of HPWH technologies that most commonly use vapor compression cycles and utilize refrigerant fluids to move heat instead of generating, leading to 200% to 400% greater efficiency. HPWH applications can be broken out into:

• Unitary HPWHs are installed unit-by-unit HPWHs for small residential (1.5-4.5 kW in capacity output, 50-80 gallons of storage) and small commercial customers (6-10 kW in capacity output, 120+ gallons of storage). HPWH replacement is usually conducted by retailers, distributors, plumbers, and homeowners while HPWHs for new construction is installed by production builders and plumbers. Equipment can range between $1,200 and $4,000 and basic installation costs can amount to between $1,000 and $1,500. Additional equipment costs (i.e., mixing valve) is needed to provide load shifting, and there may also be additional costs related to circuit and panel upgrades. Generally, unitary HPWHs are more efficient but may face challenges to retrofit in existing buildings.

• Central HPWHs are installed to service multiple units for large residential and large commercial customers (10 to several hundreds of kW in capacity output, hundreds to thousands of gallons of storage). Design firms and developers are focused in this space. Project costs can amount to $2,000 to $4,000 per apartment unit without load shifting, with additional costs with incremental heat pump capacity and storage to provide load shifting. Many central gas boilers need to be replaced.

NRDC explained that the market needs both types. Based on 60°F inlet temperature and average COP of 3, NRDC provided a conversion table for gallons to kWh of electric storage capacity as shown below and shared that a HPWH installed today will reduce GHGs by 50% to 70% over its lifetime compared to gas-fired alternatives.

NRDC then presented the market status of controlled HPWH technologies, which are driven by OpenADR standards and CTA 2045 standard control commands. In addition, in a new docket opened in February 2020 to develop Joint Appendix (JA) 13 in the Title 24 building code requirements for HPWH demand management specifications, the CEC is developing policy drivers that would require:

• Local TOU capability and setup at installation: Permanent grid connectivity is not required but this option is designed for mass adoption with low barriers to entry and opt out. This would, however, require customers to update their HPWH as TOU periods change.

• Advanced control capability: This option has higher grid value potential but requires availability of a load-shifting program in a local area as well as customer opt-in and reliable connectivity.

• Storage and load shifting requirements

NRDC, Sierra Club, and HPWH manufacturers (Joint HPWH Parties) shared an a joint proposal to enable HPWH participation. Using existing standards and certifications (i.e., NEEA Tier 3 Version 7, Title 24 J13), HPWH eligibility for SGIP will be established. Given that HPWHs are seldom replaced (e.g., once every 10 years), the Joint HPWH parties argued that the incentive should not require appliances to have significant load shifting controls, considering the potential for significant aggregate benefits. However, HPWHs that can shift load should be provided with an additional incentive because of the additional value they can provide to the grid. Specifically, after accounting for technological and industry differences, the incentive design is proposed to be structured as follows:

• Unitary HPWHs: A midstream instant rebate would be available to the distributor, contractor, or retailer within the IOU service territories. The rebate would be given instantly “reserved” and cross-referenced with available SGIP funds and the distributor, contractor, or retailer would receive reimbursement on a monthly basis. Additional eligible project costs would be applied for via an additional rebate process once work is complete and proven.

• Central HPWHs: A two-step process is proposed wherein the incentive amount is reserved and then the project is built and paid upon verification. Due to longer project lifecycles (18-24 months) than smaller projects, developers need assurance that incentives will be available at time of project completion.

All HPWH projects shall be eligible for additional project costs, including: labor, panel upgrades, wiring, supply and return plumbing, electrical components, expansion tanks, code required upgrades, and construction costs. The developer cap should be eliminated for the HPWH rebate. HPWHs that receive an SGIP incentive shall not be eligible for other active rebates or incentives. Projects serving DACs shall be given a special adder or have funds reserved separately. Participants expressed reservations on having a pre-approved list for HPWHs as a barrier to participation. Finally, some participants argued that it would be valuable to provide solar panel incentives to bolster HPWH adoption, noting that this could be a limitation mainly for residential Equity customers.

On May 7, 2020, a workshop was held to further discuss GHG compliance, verification processes, equipment eligibility (e.g., JA 13, NEEA 6.0/7.0), application portal design, incentive stacking (i.e., with energy efficiency program incentives), and incentive amounts. The HPWH parties, led by NRDC, presented on how the CPUC needs to differentiate SGIP incentive treatment for unitary and central systems, where the former typically involves plumbers who are contracted by homeowners, such that it may be preferable and easier to have incentives be claimed upstream at the manufacturer or distributor level while the plumber simply cross-references an database to verify customer eligibility. For the latter, the current SGIP application and incentive design may be more suitable. A proposal for eligible project costs was also presented (e.g., wiring costs in base, panel upgrades as separate line item cost). A SMUD representative was a key panelist to share their experiences on developing an HPWH incentive program. In particular, SMUD’s program is structured with a point-of-sale rebate where contractors handle the rebate paperwork and can help the customer avoid the price differential.