Integrated Resources Plan Working Group Wiki

Integrated Energy Policy Report (IEPR)

Background

The CEC produces an annual load and distributed energy resource (DER) forecast that feeds into system and distributed resource planning models. 

2020 Cycle

On January 17, 2020, a draft 2020 IEPR Scoping Order was published that proposed a key focus on three products: (1) a report on transportation trends, challenges, and opportunities; (2) an update to the demand forecast; and (3) an assessment of microgrids. Many parties were supportive of the focus on transportation electrification, with PG&E adding that the scope should include car-sharing electrification and SCE recommending an assessment of whether current programs can ensure achievement of the state’s transportation electrification goals. Regarding demand forecast updates, PG&E commented on the need to reflect dynamic changes with load migration while CSE wished to have a method to include updates that reflect DER impacts. Finally, on microgrids, SMUD and CSE requested that the scope be expanded to consider broader resiliency needs, potential to value stack with microgrids, and V2G for resiliency.

2019 Cycle

On January 31, 2020, the final 2019 IEPR was published that outlined comprehensive energy policy issues as well as the usual demand forecast updates. Notably, building and transportation electrification were featured in the report as critical to eliminating emissions, in addition to the need to equity concerns about ensuring all Californians benefit from the clean energy future

Demand Analysis Working Group (DAWG)
On August 1, 2019, a preliminary energy demand forecast was be shared at a DAWG meeting, including baseline forecasts for EVs and self-generation, which are increasingly leveraging NREL’s dGen model. NREL’s dGen model forecasts DER adoption using agent-based model simulation of consumer decision-making. Currently, the CEC is using this model to forecast distributed solar adoption, which has made improvements to spatial resolution, consideration of different segments such as multi-family buildings, and incorporation of rate impacts. NREL said it is “back-casting” the model to historical adoption levels to validate and calibrate the model and to better understand the effect of geospatial resolution and the influence of payback periods on the goodness of fit. In conducting this calibration, NREL found that historic payback periods do not improve the fit but found that adoption had a modest sensitivity to load and electricity rate growth and a more acute sensitivity to PV prices.

In the 2019 IEPR to take effect in 2020, the additional achievable PV (AAPV) forecast will be incorporated into the baseline PV forecast to account for 2019 Title 24 standards for new homes. Particularly, the CEC shared how it is moving toward hourly loads and hourly projections of energy efficiency, EV, and PV impacts by TAC area to better capture “peak shift” to provide more accurate peak forecasts for the purposes of determining RA and daily ramping needs. New EV load profiles were developed based on residential EV charging data from ChargePoint and the Joint IOU Electric Vehicle Load Research Report. In the future, the CEC plans to incorporate hourly impacts of storage, load-modifying DR, residential TOU rates, and climate-change-driven temperatures. In late September, the CEC will share and discuss their planned updates for energy storage profiles and modeling changes to forecast adoption.

Some of the other key takeaways included the following:

• Climate change impacts (e.g., extreme heat conditions) on residential and commercial heating and cooling have recently been incorporated into the high demand scenarios.

• SCE recommended the incorporation of higher light-duty ZEV forecasts (e.g., 7.8 million ZEVs by 2030 and 30% electrification of water and space heating as opposed to CEC’s 5.9 million ZEVs and 20% building electrification assumptions in its high-electrification scenario) as done in their PATHWAYS model to meet the state’s GHG emission targets for use in IRP modeling.

• SCE recommended the pairing of BTM solar and storage in the IEPR load forecast given adoption trends, along with projected hourly impact where storage is largely charging from mid-day solar and discharging during peak load periods in the evening.

On December 2, 2019, the CEC staff presented on specific forecasts of transportation electrification, additional achievable energy efficiency savings, and BTM distributed generation and storage impacts. For BTM storage, the CEC detailed how it used the SGIP Weekly Statewide Report to determine the installed capacity to date and how it applied different methodologies for forecasting storage adoption for the residential sector (where almost all systems are paired with PV) and for the non-residential sector (where most systems are standalone). The Draft 2019 IEPR Report was published on November 8, 2019.

For non-residential storage forecasts, the CEC proposed a methodology to take the average of 2018 capacity, 2019 capacity, and the SGIP program queue (multiplied by some factor conveying “likelihood of installation”). There are some concerns with this approach since the forecast is limited by the SGIP application queue, not taking into account changes in incentive rates, capital costs, or rate schedules, and appears to constant linear growth based on these anchor historical data points (i.e., trend analysis).

For residential storage forecasts, the CEC proposed a high and low adoption methodology, with the former linking adoption to PV adoption (by calculating a “storage adoption rate” based on storage capacity added in 2018 as a ratio of total installed PV capacity, which is then multiplied against the PV forecast) and the latter using historical trends, similar to what is being used for non-residential storage forecasts. The mid case would use the average of the high and low scenarios.

Importantly, the CEC developed hourly forecasts for energy storage systems for the 2019 IEPR to better account for the effect on non-coincident peak demand. The charge and discharge profiles are based on the 2017 SGIP Storage Impact Evaluation report, which accounts for different non-residential building types and system sizes as well as profiles by month and hour. Specifically, the CEC will model non-residential storage systems as reducing demand charges, which involve peak discharge during afternoon hours and peak charging between 9pm and 2am. However, since the SGIP report does not include sufficient data for residential storage projects, the CEC proposed to use NREL’s System Advisor Model (SAM), inputted battery specifications based on the Tesla Powerwall (13.5 kWh capacity, 5 kW rated power), and generated charging and discharging data based on solar production, default hourly household electricity load profiles, and rate structures applicable to different regions in the state. Operational requirements for ITC and SGIP compliance and minimum state of charge (i.e., 20%) for backup constrain the modeled system and was otherwise optimized for bill savings. Notably, based on these constraints and parameters, residential storage systems are only “allowed” to discharge in summer months in peak TOU periods in SAM for PG&E and SDG&E due to the insufficient rate differentials in winter months.  

There are several other areas that were discussed at the DAWG, as shown below:

• BTM PV energy grows at 8.7% per year (CAGR) and reaches 40,800 GWh by 2030. In addition to historical installed capacity, the forecast is informed by residential and commercial models that calculate payback and fuel savings. Additional achievable PV (AAPV) is incorporated in the baseline PV forecast in the 2019 IEPR, which accounts for Title 24 standards for new homes (80% level of compliance with average system size in the mid case) that takes effect in 2020.

• For electric vehicles (EVs), light-duty electric vehicles (LDEVs) consume 15,000 GWh by 2030, with 70% attributed to residential charging, while medium- and heavy-duty (MDHD) EVs grow from 22 GWh in 2019 to 1,300 GWh by 2030.

• Climate change impacts are applied to the mid and high cases, while the CEC discussed some of the challenges of forecasting cannabis load impacts in the forecast due to the lack of historical data and uncertainty around energy intensity.

Staff also presented an exploratory analysis of potential fuel substitution impacts, though such impacts will not be included in the CEC’s demand forecasts.

SB 100 Report

Background

SB 100 established the 100% policy that eligible renewable energy resources and zero-carbon resources supply 100% of all retail sales of electricity to California end-use customers by December 31, 2045 and 100% of electricity procured to serve all state agencies by December 31, 2045. It expanded the RPS as follows:

• 20% by December 31, 2013

• 33% by December 31, 2020

• 50% by December 31, 2026

• 60% by December 31, 2030

Furthermore, the 100% policy shall not increase carbon emissions elsewhere in the western grid and shall now allow resource shuffling. The CPUC, CEC, CARB, and all other state agencies shall incorporate this policy into all relevant planning and shall do all of the following:

• Maintain and protect the safety, reliability operation, and balancing of the electric system

• Prevent unreasonable impacts to electricity, gas, and water customer rates and bills, taking into full consideration the economic and environmental costs and benefits

• Lead to the adoption of policies and taking of actions in other sectors to obtain GHG emission reductions

• Not affect in anny manner the rules and requirements for the California RPS Program

By January 1, 2021, the CPUC, CEC, and CARB must issue a Joint Agency Report in consultation with all California balancing authorities to the Legislature and at least every four years thereafter. 

On September 5, 2019, a joint agency workshop was held to initiate the process for developing the joint-agency report and to present each agency’s perspective on the context for the report, including an overview of the state’s existing policies, IRP processes, programs, and reports. icy drivers. The presentations highlighted how California will need a drastic decrease in GHG emissions to achieve the 2030 and 2050 targets, with transportation needing to be a major focus area given that this sector constitutes 41% of total state emissions. Overall, these workshops are focused on the “scoping stage” of SB 100 report development, so there were no details on what the Joint Agencies will do. SB 100 provided limited guidance on this report, so it is unclear on what the Joint Agencies will use this report for. However, as a potential visioning document, CESA will be focused on how energy storage is positioned in the SB 100 discussions. Eventually, SB 100 requirements will feed into the CPUC’s IRP process.

CESA provided a high-level overview of the important role of energy storage resources of all kinds (battery, long-duration, mobile/EV, thermal, hybrid, hydrogen) that can support the state’s SB 100 goals. Given that policymakers were characterizing energy storage as battery storage only, potentially overlooking the wide range of technologies, configurations, and applications, CESA sought to remind policymakers on positioning energy storage more broadly in the Joint Agency Report.

See CESA’s comments on September 19, 2019 on the Scoping Workshop

Draft & Final Results

On August 31, 2020, the joint agencies published the draft results of SB 100 modeling analysis conducted for the statutorily-required Joint Agency Report. The Joint Agency Report is to be prepared collaboratively by the CEC, the California Public Utilities Commission (CPUC), and the California Air Resources Board (CARB). The CEC noted that all results contained in the draft results package are directional in nature and do not yet represent a "state plan" to achieve the goals set forth by SB 100. Within the draft results, the CEC includes three sets of scenarios:

• Reference scenario: These scenario models the counterfactual case to SB 100 – i.e., a case where the sole environmental target is the 60% RPS requirement by 2030. This case is used for comparative purposes.

• Core scenarios: These reflect the Joint Agency interpretation of SB 100 which does not include T&D and storage losses within the scope of the needed decarbonization.

• Study scenarios: These expand the Joint Agency interpretation of SB 100 to include T&D and storage losses.

The modeling uses RESOLVE, the same capacity expansion model utilized in the CPUC's Integrated Resource Planning (IRP) proceeding. Relative to the IRP version of RESOLVE, E3 included the following modifications for this study:

• All resources can be selected as candidate resources.

• The model has been modified to encompass all of California and not just the CAISO area as it is used in IRP.

• The out-of-state wind potential has been increased to 12 GW.

• The offshore wind potential has been increased to 10 GW.

• The option to select natural gas generation paired with carbon capture and sequestration (CCS) has been removed due to insufficient cost data.

Each of the modeling scenarios were analyzed under different demand cases derived from PATHWAYS, another E3 model. These cases include:

• A Reference Case based on the Integrated Energy Policy Report (IEPR) developed by the CEC. This case has the lowest resource adequacy (RA) requirement by 2045.

• A High Biofuels Case, where the use of biofuels is more widespread and displaces traditional thermal generation. This case has the second-lowest RA requirement by 2045.

• A High Hydrogen Case, where electricity is used to obtain hydrogen through electrolysis, substantially increasing load. This case has the second-highest RA requirement by 2045.

All portfolios presented were discussed as being directional in nature – i.e., it does not represent a “state plan” to reach SB 100 goals. The E3 team concluded that SB 100 is achievable using existing technologies, with further innovations and cost reductions in zero-carbon technologies reducing implementation costs. Portfolio diversity is generally valued by the model, and natural gas capacity is largely retained, though fleet-wide utilization decreases by 50% compared to the 60% RPS future (Reference Scenario). Notably, sustained record-setting resource build rates will be required. In response to previous comments, the joint agencies concluded that attribute-based criteria for zero-carbon resources have been developed instead of a prescriptive list of candidate technologies, many of which may lack adequate data, and consistent with RPS, the modeling will only consider retail sales and state loads and not include system losses in the definition of supply.

The draft results show future grid mixes that are heavily dominated by solar PV generation and energy storage (see chart below). Specifically, for battery energy storage, the Core and Study scenarios show a need for about 20 GW by 2035 and over 40 GW in 2045. Long-duration storage is selected in all cases, proving to be necessary by 2027. Notably, the need for long-duration storage increases substantially in 2035 within the Core and Study scenarios. Across the different demand cases in the Core scenario, storage selections are stable, with the main source of variation between demand cases being the level of solar PV deployment. While most cases retain the vast majority of natural gas generation, usage of these assets substantially drops in both the Core and Study scenarios (relative to the Reference scenario). In the Reference scenario, gas generation amounts to 24% of all generation; in the Core and Study scenarios, on average, this figure is 9% and 4%, respectively. As expected, costs increase as environmental constraints become more binding. Under the High Electrification case, the draft results show average cost increases of 8% and 16% by 2045 for the Core and Study cases, respectively.

Meanwhile, sensitivities show a clear relationship between wind availability and storage needs (see chart below). As more wind is available, more of it can be used to balance solar generation and less storage is required. Resource selections for long-duration storage are less disturbed by increased wind availability, highlighting that different sorts of storage provide different grid services and benefits. While most cases retain the vast majority of natural gas generation, usage of these assets substantially drops in both the Core and Study scenarios (relative to the Reference scenario). By contrast, under the No Combustion scenario, this case results in sizable increases in the selection of utility-scale solar PV (from about 68 GW to about 90 GW) and battery storage (from about 50 GW to about 65 GW), in addition to the selection of about 25 GW of hydrogen fuel cells, by 2045 relative to the Core scenario under the High Electrification demand case.

The CEC performed analysis including two generic zero-carbon firm resources (ZCFR) to consider the fact that modeling limitations and lack of established cost data precluded a range of ZCFR from being included as candidate resources. The inclusion of these candidate resources (Generic Baseload and Generic Dispatchable) results in a substantial drop in selected capacity, primarily at the expense of long-duration storage, battery storage, and utility-scale solar PV. The CEC also modeled a No Combustion case, which resulted in the selection of about 25 GW of hydrogen fuel cells by 2045. Under the No Combustion case, hydrogen and battery storage fulfill most of the RA requirements of the state by 2045. Notably, the results highlight a deployment challenge with record-level buildouts. For example, in the last ten years, solar PV deployment has averaged about 1 GW per year, with a maximum value of 2.7 GW per year. For storage, the 10-year average is very close to 0, as deployment has yet to reach the GW scale. However, the average build rates to 2030 and 2045 within the High Electrification demand case shows that 1.1 GW of battery storage would need to be built every year to meet the 2030 need. This number increases to 2.2 GW considering 2045 needs. If SB 100 goals are accelerated to 2040, 2035, or 2030, the yearly build rate increases to  3 GW and 2.2 GW per year for solar PV and battery storage resources, respectively.

CESA served on the Resource Buildout panel and recommended that the Joint Agencies use the Draft Results to identify near-term, no-regrets procurement opportunities and adopt the interpretation of SB 100 used for the Study cases, as it most closely reflects the Legislature’s intent that includes retail sales, state loads, T&D losses, and storage losses within the coverage of zero carbon load by 2045. RESOLVE must also be modified to solve for long-duration storage needs and include long-duration storage candidate resources beyond pumped hydro storage. Furthermore, the Joint Agencies should clarify the optimization of energy storage operations within RESOLVE regarding the interactions between RPS and RA incentives. Finally, hydrogen must be integrated as an alternative drop-in fuel within the SB 100 Joint Agency Report, including the benefits and flexibility that hydrogen can bring to the electric sector and as a drop-in fuel to replace natural gas.

See CESA’s comments on September 15, 2020 on the SB 100 Modeling Draft Results

At the workshop, given the directional nature of the workshop that focused less on near-term viability of different resource types, many stakeholders expressed disagreement with some of the resource-specific inputs and assumptions used. The joint commissioners generally sought feedback on what they can do as executives at the regulatory agencies to support 2045 needs, including the substantial resource buildout required (e.g., permitting, siting). To this end, the CAISO expressed how procurement needs to begin as soon as possible to support long-term transmission investments. In comments, many parties highlighted the need to conduct reliability studies, affordability and rate impact analysis, include environmental and land-use screens, and expand the joint-agency team given the need to take a more comprehensive approach.

Deep Decarbonization Scenarios

On September 24, 2019, a joint agency workshop was held by the CEC and CARB on California’s climate and energy policies to discuss the scenarios and assumptions for achieving deep decarbonization by 2050, where significant work is needed in eliminating emissions from the transportation sector and to transition to “sinks” of carbon, not sources. At the same time, reliability must be maintained via control of not only the supply side via control settings for inverter-based generation but also the demand balance via price signals and rates. E3 also highlighted how wind, solar, flexible loads, and batteries provide low-cost GHG emissions reduction (90-95% decarbonization of the electricity) but do not get the state to zero carbon, which requires firm capacity (e.g., gas with CCS, biomethane, nuclear) and long-duration storage (e.g., hydrogen). Overall, the workshop invited non-California and academic stakeholders to present their cutting-edge research and lessons learned.

On November 18, 2019, a technical workshop was held to discuss technologies, inputs, and modeling scenarios for technical analysis to inform the joint agency report. The CEC began with a question around what should count as eligible renewable and zero-carbon resources and proposed the following options:

• RPS+ would align with the definition of current RPS resource types and add generation types that count as zero-fossil-emissions (e.g., large hydroelectric, nuclear, natural gas with carbon capture and zero emissions).

• No Combustion would be similar to RPS+ but prohibit resources that combust fuel, which would include biomethane reformation and natural gas reformation with carbon capture and zero emissions but not allow biomass and biomethane combustion and natural gas combustion.

However, the CEC noted that accounting differences mean that the same electricity source type might be considered very differently – e.g., RECs for RPS and emissions profile for Mandatory Greenhouse Gas Reporting Regulation (MRR). Meanwhile, the joint agencies will leverage existing studies to conduct some preliminary modeling (e.g., CEC Deep Decarbonization Report, SB 100 2045 Framing Study for CPUC’s IRP).

The CPUC staff presented an overview of their 2045 framing study from the IRP proceeding, finding that beyond 2030 outlooks help to inform near-term thermal retention decisions and that all three scenarios rely heavily on solar and batteries to meet load and GHG goals. The availability of out-of-state or offshore wind displaces in-state solar and batteries and lowers costs, highlighting how resource diversity lowers the cost of meeting long-run GHG goals.

CESA presented on the “Enabling Technology Options” workshop panel to highlight innovation and emerging technologies that could assist with achievement of SB 100 goals by 2045. Specifically, CESA presented on the various energy storage technologies, durations, technologies, performance characteristics, cost trends, and market size. There were a number of other panelists representing different technologies as well, including the following:

• Biomass & biofuels: A UC Davis speaker presented on the potential for biofuels to provide energy-dense liquid fuels and cross-sectoral benefits (e.g., transportation, agriculture) but face barriers in terms of RPS ineligibility and problematic definition for gasification.

• Demand flexibility: LBNL identified load shifting as the biggest market opportunity and shared its analysis of DR market potential and cost trends for various end-uses and technologies, including battery and thermal storage.

• Gas retrofits: Noble Thermodynamics presented on the necessity of gas and how carbon capture technologies and other gas retrofits can support GHG emissions reduction while ensuring reliability.

• Geothermal: Fervo Energy discussed how the future of geothermal technologies is flexible and reliable and has a low land footprint.

• Hydrogen: Green Hydrogen Council (GHC) highlighted how green hydrogen can decarbonize multiple sectors and provide seasonal storage shifting capabilities.

• Nuclear: Breakthrough Institute presented on emerging technologies that are modular and more flexible but face challenges due to the statewide ban on new nuclear and the lack of value as a low-carbon resource.

• Wind: Pattern Energy discussed how wind technologies are increasing energy yields with taller hub heights and larger rotor diameters and how out-of-state wind can support regional diversity that reduces costly curtailment. Meanwhile, Offshore Wind California highlighted the state’s resource potential but discussed how there are barriers to transmission capacity, permitting, and creditworthy off-takers.

Finally, SCE presented on its updated Clean Power and Electrification Pathway white paper that found that economy-wide carbon neutrality by 2045 will require a transformation of how the state sources and uses energy, especially in transportation and buildings and that a sense of urgency is needed to achieve 2030 goals.

CESA provided feedback on how energy storage can enable California to reach its SB 100 goals. Specifically, CESA commented on the need for storage diversity to accomplish decarbonization goals and the potential of energy storage to minimize the environmental impacts of fossil-fueled capacity via retrofitting. CESA also recommended the inclusion and consideration of demand-side solutions and technologies (such as electrical space and water heaters) as a means to shape and shift load, potentially lowering future resource costs. Finally, the CEC should reform the modeling approach currently considered to include multi-day optimization of dispatch, additional storage technologies as candidate resources, and LOLE reliability tests on future resource-build scenarios.

See CESA’s comments on December 2, 2019 on the technical workshop

Modeling Overview

PATHWAYS is E3’s economy-wide infrastructure-based greenhouse gas (GHG) emissions and energy analysis tool that models physical energy flows in all sectors of the economy (e.g., building appliances, on-road vehicles) and tracks electrification load shapes by sector and end-use. Rather than making forecasts, PATHWAYS allows hypothesis testing predicated on meeting emissions targets and bottom-up electricity demand projection based on end-use appliance stocks and macroeconomic drivers (e.g., number of households). PATHWAYS outputs include annual loads by category (GWh/year), normalized 8760 load shapes, and electricity sector GHG trajectories that can be provided to capacity expansion models such as RESOLVE.

RESOLVE is a linear optimization model explicitly tailored to study of electricity systems with high renewable and clean energy policy goals. The optimization balances fixed costs of new investments with variable costs of system operations, identifying a least-cost portfolio of resources to meet needs across a long time-horizon. RESOLVE is a zonal model that optimizes investment decisions in the “main” zones and treats other zones with exogenous assumptions. Flows are impacted by intertie constraints (e.g., min/max, simultaneous, ramping) and hurdle rates. Flexible resources are selected in RESOLVE when the avoided cost of renewable overbuild falls below the marginal cost of the integration solution. For each year in the analysis horizon, RESOLVE models the operations for 37 separate representative dispatch days – a sampling algorithm designed to approximate long-run distributions of hourly load, renewable generation, and hydro energy. 

The capacity of new build resources are variables that the model can optimize, expanding existing units or building completely new units. Existing thermal resources can be economically retired if ongoing fixed cost is not supported by value of system services. New renewable costs include not only installation and fixed O&M costs but also new transmission costs, if needed, ranging from $11/kW-year to $89/kW-year depending on the Competitive Renewable Energy Zones (CREZ). Out-of-state transmission costs represent the cost to wheel power across adjacent utilities’ systems or the cost of developing new out-of-state and in-state transmission lines, with full capacity deliverability costs derived from OATTs and the CEC’s Renewable Energy Transmission Initiative 2.0 (RETI 2.0), ranging from $29/kW-year to $143/kW-year. Storage costs are broken into additive power ($/kW-year) and energy ($/kWh-year) components, which allows RESOLVE to optimize power and energy duration independently. In addition to unit commitment and production simulation, RESOLVE includes constraints for load following reserves, energy sufficiency, and resource adequacy. Variable resources provide capacity toward PRM based on ELCC surface expressed as a piecewise linear function of wind and solar penetration, while storage provides capacity toward PRM requirement based on NQC derate and qualifying duration. Shed DR is included based on the LBNL DR Potential Study and is assumed to have an NQC toward PRM equal to 1-in-2 ex ante peak load impact.

On February 24, 2020, a joint agency workshop was held to discuss inputs and assumptions for the SB 100 study. Staff and consultants presented background on the model to be used for the quantitative SB 100 analysis, including inputs, assumptions, and planned scenarios. While the current modeling efforts will focus on capacity expansion modeling and production cost modeling, CEC staff solicited input on ideas for future modeling possibilities around environmental protection, affordability, and safety. In previous comments, CEC staff observed support for a diverse portfolio, considerations around air pollution, and the need to properly define candidate resources eligible for SB 100 goals. Four PAHTWAYS load scenarios will be used in SB 100 modeling as an input into RESOLVE, with the main difference across the scenarios being around on-road vehicle electrification:

• Reference Scenario using updated state reference aligned with the 2019 IEPR Mid Scenario

• High Electrification Scenario including electrification of building and transportation, high energy efficiency and renewables, and limited biomethane

• High Hydrogen Scenario including more fuel-cell trucks and fewer all-electric vehicles

• High Biofuels Scenario including higher biofuels and purpose-grown crops and thus fewer GHG mitigation measures needed in transportation and other sectors

Seven scenarios have been proposed by the joint agencies using three zero-carbon resource options, where “RPS+” includes RPS-eligible technologies, large hydroelectric, nuclear, and natural gas with carbon capture and sequestration and “No Fossil Fuel Combustion” is the same as “RPS+” but without allowing any natural gas combined with CCS.

Unlike for the CPUC’s IRP modeling process where modeling was only conducted for the “CAISO zone”, the SB 100 analysis will include all four California balancing area authorities, such that RESOLVE will model a single “California zone”. Both supply-side and demand-side resources are included as candidate resources, with the only notable addition as compared to the IRP modeling being carbon capture and sequestration (CCS). Storage resource capital and O&M costs will come from Lazard Levelized Cost of Storage (LCOS) 5.0 and NREL’s Solar+Storage Study, as previously recommended by CESA. Furthermore, hydrogen fuel cells are modeled as candidate resources, though hydrogen can also be modeled as a drop in fuel for existing gas generators.

Notably, E3’s presentation also showed how battery storage and PHS are able to share energy between days, a feature that was not previously available when only intra-day optimization could occur. However, it is unclear if this enables inter-day optimization since E3 also shared in its modeling documentation that storage dispatch is constrained by energy neutrality with each dispatch day. CAISO discussed some of the unanswered questions around whether and how solar and storage can meet the majority of flexibility and energy needs that can no longer rely on gas and other dispatchable resources. CAISO estimated that 25 GW of flexible ramping capacity will be needed by 2030.

Especially on multiple days of cloud coverage, CAISO said they are exploring the strategic retention of gas for energy and other grid services. On low solar production days, CAISO expressed concerns with the ability of storage to recharge. Interestingly, the CAISO expressed their view that limited testing of more technologies is needed to prove potential scaling before making a significant investment in a limited, non-diverse portfolio.

A stakeholder panel discussed considerations for inputs and assumptions related to reliability, land use, equity and environmental impacts. Municipal utilities and irrigation districts also discussed the SB 100 reliability, operational, and stranded/investment cost challenges for a grid that includes less inertia, more variable load, and more intermittent generation, but at the same time, they highlighted the need for various storage technologies and capabilities. Other topics covered included:

• Reliability: CAISO discussed some of the unanswered questions around whether and how solar and storage can meet the majority of flexibility and energy needs that can no longer rely on gas and other dispatchable resources, especially on multiple days of cloud coverage. New duck curve data was shared on actual 2019 ramping needs and projected 2030 ramping needs based on the IRP Reference Portfolio..

• Land use: The Nature Conservancy (TNC) provided an overview of the need to integrate environmental and land use data in long-term energy models to improve projects and policy decisions. With clean resources sourced from a broader west, TNC argued for the cost-effective and land conservation benefits of expanded resource availability, with out-of-state wind being preferred as a balancing resource, displacing battery storage even in scenarios with higher levels of land protection. In the highest land use protection scenario, battery storage still represented a major balancing resource.

• Workforce development: Citing research on the potential employment impacts of renewable electricity development and building decarbonization and the SOMAH Program as a case study, GRID Alternatives presented on the importance of a equity-focused workforce development strategy. GRID recommended funding set-asides within program budgets, use of cross-sector partnerships, and engagement with community groups.

CESA supported the modeling efforts but recommended that the Joint Agencies should clarify and interpret SB 100’s intent to phase out the use of fossil fuels. In addition, CESA commented on how RESOLVE is not currently equipped to solve for long-duration storage needs and recommended that transmission planning cannot be done solely in an ex post fashion. In response to workshop participant discussion, CESA added reliability concerns within the CAISO footprint can be solved with modifications to existing market mechanisms and that energy and capacity needs can be addressed in ways that minimize fossil fuel use.

See CESA’s comments on March 9, 2020 on the Inputs & Assumptions Workshop

A number of other parties submitted comments. Technology-specific parties advocated for the inclusion or fair consideration of their resource, such as hydropower, hydrogen, carbon capture and sequestration (CCS), offshore wind, and CAES. In particular, some parties were concerned that offshore wind and out-of-state wind were the only resources that were only available in certain scenarios. Others commented on the need to consider affordability and projected T&D costs and to provide more transparency and allow for detailed technical input into the assumptions used. Meanwhile, some utilities expressed concerns with the limitations of the RESOLVE model as being zonal and utilizing weather years based on sampling (i.e., 37 representative days); this is limiting in the sense that it fails to capture internal transmission constraints, is unable to model multiple and simultaneous constraints, does not look at unplanned events, and does not capture 8760 reliability. SCE also had concerns with expressing affordability and costs in average $/kWh and instead recommended “share of wallet” analysis that accounts for energy efficiency gains and reduced gasoline consumption.

Solar-Storage Modeling Tool

Background

The CEC opened a new docket titled “Modeling Tool to Maximize Solar + Storage Benefits” (Docket 19-MISC-04) to introduce a new modeling tooldeveloped by E3, which interfaces with an enhanced LNBA tool and optimizes the operation of dispatchable DERs based on an optimization algorithm. Specifically, this tool evaluates the benefits of solar, storage, and other DERs and estimates the value proposition of the integrated systems based on their expected optimal operations, location on the grid, market prices, and other characteristics. This project is being conducted as part of EPC-17-004 and the resulting tool will be used to evaluate solar-plus-storage systems being researched in other EPIC projects (GFO-16-309).

Tool Development & Demonstration

On June 13, 2019, a workshop was held to introduce the tool, review the user guide and functionalities, discuss how the tool can simulate the operations of DERs under tariff and program designs, and determine which design will maximize the benefits of DERs to ratepayers. The tool co-optimizes dispatch of storage with other DERs (either via fixed DER shapes or optimized dispatch) and uses a nesting model of local distribution benefits. The tool is capable of evaluating and sizing a DER portfolio for distribution deferral while producing financial pro forma models (e.g., all-in project costs, financing options) and cost-effectiveness analysis for the utility (e.g., LNBA, bid evaluation, DER program design) and for the customer, developer, and aggregator (e.g., customer payback, expected return on investment). The dispatchability function seeks to minimize net costs, subject to technology, market, incentive, and price-taking constraints, over different windows (daily, monthly, annual) or intervals (hourly, 15 minutes, 5 minutes) and is capable of taking into account customer comfort level and other DER technologies. The model is also able to capture the nesting impact of DERs not only deferring direct distribution investments but also further upstream investments.

There was further discussion on use cases, how the tool can be used in the DRP proceeding, and the development of a storage roadmap. E3 explained that this tool will enable the IOUs to incentivize customer use of DERs through their tariffs and programs and align this use with the needs of the electricity grid. By incentivizing the provision of grid services from DERs, IOUs can avoid buying those services from other providers, reduce fuel burn, avoid investments in new generation capacity, and defer investments in new transmission and distribution infrastructure, leading to lower electricity costs to ratepayers.

On August 19, 2019, a workshop was held where CEC staff, in consultation with E3, presented and discussed the cost-effectiveness results produced by the modeling tool for an ongoing EPIC-funded project by Humboldt State University Sponsored Programs Foundation that aims to address key market barriers to deploy a solar and storage technology system at the Blue Lake Rancheria gas station and convenience store located in Blue Lake, CA. E3 also provided a hands-on demonstration and training for stakeholders who are interested in using the tool and guided stakeholders through the process of creating inputs, analyzing the cases, and viewing the final results. CEC/E3 staff were specifically looking for feedback on the usefulness, user-friendliness, and key features of the modeling tool.

CESA offered feedback on how this tool could be improved to be more useful for stakeholders beyond the "policy use case" that looks at all the potential theoretical value stack of solar-plus-storage resources and instead accounts for real-world constraints as well as linking to capacity methodologies and values used in CPUC proceedings to ensure usefulness of the tool's outputs to utility and industry stakeholders.

See CESA’s comments on September 9, 2019 on the Second Workshop

On December 12, 2019, a final workshop on the tool was held to summarize the Solar + Storage Modeling Tool, discuss the changes and improvements to the tool since the initial public release, review case studies in which the tool was used to assesses the cost effectiveness of PV, storage, and other DER technologies, and discuss recommendations and next steps.

Technology & Resource Roadmaps

Background

The CEC is the state agency in charge of developing a roadmap to map out the opportunities, barriers, and potential pathways to realize a state policy objective or goal. The CEC, for example, developed the Energy Storage Roadmap to support progress toward AB 2514 energy storage procurement targets.

Vehicle-Grid Integration (VGI) Roadmap

The intent of updating the roadmap is to address the needs to use open standards that advances greater grid integration and support the state’s 2025 zero-emission vehicle (ZEV) adoption goals.

On September 6, 2018, a joint agency webinar workshop was held on September 6 to kick off the process to update the California VGI Roadmap. The CEC presented the approach and schedule for the roadmap update, as well as the matrix that includes proposed VGI roadmap goals and the problems/issues to address to achieve such goals.

On October 29-30, 2018, a two-day workshop was held to receive public input on specific roadmap actions and priorities. The workshop featured a vehicle and charging technology showcase for the public and stakeholders to learn about VGI efforts, followed by a staff presentation on an overview of the VGI Roadmap process as well as updates to the draft matrix of goals, issues, and barriers. The California Electric Transportation Coalition (CalETC), representing utilities, auto OEMs, and some EVSE providers, highlighted the need to open up different applications, control approaches (e.g., TOU and demand charge rate design, dispatching), and VGI communication pathways, and recommended policy steps to be taken on exploring DR program participation, LCFS program design for smart charging incremental credit (effective January 2019), and storage mandate design to qualify both V1G and V2G. E3 and LBNL also shared their learnings on the potential of V1G and V2G to support the grid.

CESA focused on how to realize greater value to customers and ratepayers and better achieve our decarbonization goals by enabling the smart operationalization of EVs and EVSEs. CESA focused on the barriers related to market participation pathways, dual DR program participation and multiple-use applications, and compensation structures that should be included in the roadmap and addressed in CPUC, CAISO, and CEC proceedings.

See CESA’s comments on November 21, 2018 on the VGI Roadmap Update Workshop

Renewables Roadmap (19-ERDD-01)

The CEC is developing a roadmap for prospective renewable energy expansion in California. The purpose of the research roadmap is to identify, describe, and prioritize research, development, demonstration, and deployment (RDD&D) on technology opportunities that have potential to achieve high penetration of renewable energy into California’s electricity grid. These efforts seek to identify and prioritize research on the most critical RDD&D gaps that need to be addressed to achieve California’s goals for integrating high penetrations of renewable energy resources in IOU service territories. Results of the analyses may be used to strategically target future EPIC investments. The CEC retained Energetics, Inc. to conduct this project and prepare the roadmap and reached out to CESA to complete a survey to support this effort.

On March 25, 2019, CESA provided feedback on how energy storage related RDD&D should focus on key applications that will likely be needed to achieve the state's SB 100 goals and mitigate climate risks such as wildfires. Rather than focusing on technologies, CESA recommended a focus on applications, such as resiliency and long-duration storage. 

On June 28, 2019, a webinar was held to discuss the current baseline, best in class, cost, performance targets, and recommended initiatives for PV solar, concentrated solar, land-based wind, offshore wind, bioenergy, geothermal, small hydropower, grid integration, and energy storage technologies. The key questions were around the cost and performance targets for each technology and whether there were any gaps in the identified research areas and initiatives. For the grid integration technologies technology area, the draft report focused on T&D infrastructure, devices and controls, modeling and resource planning, and resilience. Initiatives were proposed to support continued advancement of high-temperature low-sag conductors as well as advancement of smart inverters to improve communication and cybersecurity. For the energy storage technology area, initiatives were proposed to support research into long-duration energy storage systems and to fund recycling programs for energy storage systems (particularly lithium-ion batteries)

CESA supported the initiatives but recommended that energy storage funding initiatives should focus on applications and performance attributes, including storage for resiliency and non-wires solutions as a topic in the grid integration strategies area of the roadmap. CESA added that multi- day and season system modeling capabilities are needed to support the valuation of long and seasonal duration storage technologies, and that hydrogen storage is a seasonal energy storage resource that warrants attention in the roadmap.

See CESA’s comments on July 12, 2019 on the Draft Renewable Energy Generation Roadmap

On February 5, 2020, the CEC staff held a webinar to present the R&D opportunities identified for the EPIC research roadmap on renewable energy generation technologies for utility-scale applications to support higher penetrations of renewable energy. Two “mid-term” initiatives were identified for energy storage systems to achieve “success” in a 3-5-year timeframe:

• Initiative ESS.1: Lengthen storage duration of energy storage systems (8 hours or greater). The roadmap seeks to demonstrate the ability to provide 10-12 hours of storage duration at utility-scale, which help to reduce capacity and overbuild requirements for 4-8-hour storage by 2045 and provide renewables integration and resiliency benefits.

• Initiative ESS.2: Optimize recycling process for lithium-ion batteries. The roadmap seeks to hit a 90% recycling rate for lithium-ion batteries to improve environmental impacts and reduce lifetime costs, improving upon the current less-than-5% recycling rate.

While the analysis of the long-duration needs and the cost metrics would benefit from more rigor, CESA found it promising that the roadmap continues to focus on the need to explore ways that the CEC could support through applied R&D, pilot demonstrations, deployment support, and market facilitation activities. However, as the roadmap progresses, CESA may need to comment on how the initiative needs to be shaped to better target the appropriate benchmarks, such as achieving certain $/kWh numbers for different storage durations. Furthermore, the roadmap ambiguously targeted 10-12 hours of storage duration without reference to cost targets or why even longer-duration (e.g., multi-day, seasonal) storage should not also be included in this initiative, given that this roadmap is targeted toward 2045 needs. Finally, the recycling initiative was reasonable but lacking in much detail.

On February 25, 2020, the CEC held a technical forum at the EPIC Symposium to highlight innovative new clean energy technologies that can help improve the resiliency of California’s electricity sector to climate change impacts and extreme weather events.

DER Roadmap (19-MISC-01)

The purpose of the DER Roadmap is to provide the CEC with insight and recommendations and to develop a research roadmap that identifies, describes, and prioritizes key research and demonstration needs to enable high penetration of DERs in California. This Draft Technical Assessment provides the first step toward that end, identifying what further EPIC investments may be needed for DERs to support California’s energy and climate goals. The Draft Technical Assessment characterizes the current state of DER technologies, answering the following questions about key technologies and strategies:

• What is the technology/strategy?

• What does the technology/strategy do and how does it compare to other technologies/strategies?

• What do we know about the technology’s/strategy’s limits?

• What is preventing the technology/strategy from further supporting California’s energy policy goals?

• What research on this technology/strategy is active in or planned by other entities?

On March 25, 2019, Gridworks and Navigant (in conjunction with CEC staff) hosted a public workshop to solicit feedback on the Draft Technical Assessment component of the DER Research Roadmap Project. The purpose of the workshop is to get expert feedback on the Draft Technical Assessment, which will serve as the foundation of our Roadmap, including recommendations to the CEC on how to prioritize future RRR&D funding in the DER space.

CESA delivered remarks at the workshop and provided feedback on the energy storage and vehicle-grid integration sections of the assessment. The draft report was a bit unclear at times, so CESA recommended a different framework that assesses the landscape of specific energy storage technologies across three categories: performance characteristics, market penetration, and prospective benefits. CESA also provided input on how certain energy storage technologies (thermal), configurations (hybrids), and tools (modeling, standard testing protocols, calculators) should be considered in this assessment as well as our feedback on the key regulatory drivers for the energy storage market. Finally, we echoed our comments on Energy Storage Research Needs to the CEC in November, proposing near-term and medium-term use cases for energy storage that the CEC should invest money.

See CESA’s comments on April 8, 2019 on the public workshop

On June 25, 2019, a Final Technical Assessment was published that incorporated many of CESA’s suggestions, edits, and corrections, including the need to create a framework for quantifying the potential resiliency benefits of energy storage, focus on hybrid storage configurations as a near-term RDD&D target, and develop modeling tools with multi-day or seasonal storage optimization dispatch as a medium-term RDD&D target.

On July 25, 2019, a workshop was held to introduce a prioritization methodology to rank potential DER research needs and produce the final Research Roadmap. Energy storage, smart inverters, DERMS, EV integration, and DERs as non-wires alternatives were identified as current research need areas. The screening and prioritization process were proposed as follows:

CESA provided feedback on key DER research priorities for energy storage and EV integration. CESA was generally supportive of the listed research areas, which were generally comprehensive, though we requested clarification and refinement to the research areas to provide clearer outcomes and insights.

See CESA’s comments on August 9, 2019 on the Draft DER Research Roadmap

On September 17, 2019, a workshop was held to summarize the research ideas submitted for the DER Research Roadmap, discuss the screening process, and share the preliminary scores and ranks of the research ideas. Staff discussed how the process has advanced; the initial feedback; the next steps in the process; and the remaining timeline for the DER Research Roadmap. Based on survey results, the Navigant team identified the following research areas as the highest priority areas.

The lowest-ranking areas revolved around PV-related and generalized (e.g., DER impact) topic areas, which have generally already had significant investment and garner sufficient understanding of their capabilities. For energy storage, the evaluation of use cases for lithium-ion and wholesale market participation of thermal storage resources ranked moderately and garnered some attention. This is the second of three public workshops to develop and prioritize DER research recommendations.

On May 29, 2020, a workshop was held to present the draft final results of the assessment to prioritize DER research and development needs. For the energy storage research need area, the following high-priority topics were identified that highlighted the role of diversifying the storage toolkit while improving the performance of existing lithium-ion battery storage technologies, all in the short- to medium-term timeframe:

• Distributed Thermal Energy Storage Aggregation: Control aggregate BTM thermal loads in response to wholesale grid signals, including communications and controls

• Evaluate Alternative Storage Technologies: Evaluate non-lithium ion storage technologies with a particular focus on multi-day energy shifting applications

• Next Generation Lithium-ion Storage: Continue to develop lithium-ion batteries with a focus on improved controls for extended battery life as well as the opportunity for local geothermal-backed lithium extraction

• Green Electrolytic Hydrogen for Long-Duration Storage: Implement distributed multi-day green electrolytic hydrogen solution to reduce wind and solar generation curtailment

Meanwhile, for the vehicle-grid integration (VGI) research need area, the CEC is also seeing the need to advance the role of EVs in providing resiliency, building on CESA’s V2G interconnection and microgrid work and lining up with the CPUC’s recent focus on this area as well:

• Vehicle-to-Building for Resiliency: Test ability of EV batteries to power community resiliency centers during unplanned outages and PSPS events

• Assess Second Life EV Batteries: Resolve questions on second-life EV batteries such as degradation rate, optimal cell matching, customer concerns, and target market price

• Assess EV Charging Technology Efficiencies: Research the impact on charging efficiency of charging at different states of charge and current and transformer capacity levels to optimize V2G requests with respect to losses

Finally, some of the key research need areas related to DER planning and strategies continue with a near-term focus on DER integration and resiliency, including:

• Valuing Resiliency for Microgrids: Develop consensus benefit figures to be used in determining the effectiveness of a microgrid or other technology that improves resiliency

• Residential Outage Backup: Prototype small battery backup systems that would seamlessly operate garage doors, emergency lighting and life safety devices in the event of wildfire or safety shutoff

Other research need areas where research priorities were identified include those for flexible load technologies and DER communications and controls.

Microgrids Future

On July 7, 2020, a workshop was held to discuss the microgrid policies, challenges, and opportunities from the perspective of CPUC/CEC staffers and vendors. Some of the key challenges that were highlighted include:

• Difficulty to fully finance with private funding: This highlights the need for public investment funds (e.g., DOE/EPIC grants, SGIP, resiliency tariff), as well as the need to standardize contracting terms. The CCAs could potentially serve as a central PPA counterparty and facilitate public sector bond funding.

• Long time to design, construct, and deploy: In addition to more complex permitting, testing, and interconnection processes, it involves a number of different vendors to coordinate and put together a microgrid configuration. The need for

• Need for significant education: Critical facility operators need education to understand the importance and optimal design of microgrids. The need for better models on value streams and technical design was also highlighted.

• Complex operations and maintenance: O&M responsibility must be pre-planned and utility bill savings must be optimized in non-islanding modes.

CESA presented at the workshop on a high-level overview of the role of storage in microgrids, including for longer-duration technologies, pairing with solar, providing economic signals, and supporting interconnection processes. The workshop was mostly informational for the benefit of the CEC and to draw lessons learned from CEC EPIC projects, technology vendors, and developers. Based on the presentations, the technology is there but it involves a number of challenges to bring projects together, interconnect and operate them, and address various financing and policy barriers. Fortunately, the Microgrid proceeding (R.19-09-009) appears to finally be getting some traction on making headway on some of these issues. Notably, the IOUs were supportive of microgrids but offered notes of caution recommended against duplicating activities in the CPUC’s R.19-09-009 proceeding. SDG&E focused on ensuring safety through testing and commissioning while SCE commented that microgrids are just one resiliency tool and how incentives for microgrids should not be funded by utility ratepayers.

Given the growing need for resiliency due to climate change risks and Public Safety Power Shutoff (PSPS) events, CESA strongly supported the joint-agency focus to support the acceleration of microgrid deployment. CESA encouraged the CEC to consider creating economic signals to value resiliency, leveraging and layering existing incentive programs to maximize ratepayer investments, funding the development of tools and additional microgrid use cases where gaps are identified, and developing commercialization pathways, including third party-owned microgrids.

See CESA’s comments on July 30, 2020 on the IEPR Workshop

2012 Long-Term Procurement Plan (R.12-03-014)

Background

The Long-Term Procurement Plan (LTPP) proceedings were established to ensure a safe, reliable, and cost-effective electricity supply in California. Every two years, the CPUC opens an LTPP proceeding to review and approve the utilities' ten-year, forward-looking procurement plans, which dictate the amount and types of resources that the IOUs need to procure through 2024. The 2012 LTPP proceeding evaluated the IOU’s need for new energy resources for system/local reliability and operational flexibility, and established rules for rate recovery of approved procurement transactions in four separate procedural ‘tracks’. The long-term nature of resource planning is necessary given that resource procurement decisions typically take three to nine years until fruition.

The CPUC updates the planning assumptions on an annual basis in coordination and collaboration with the CAISO and the CEC through an Assumptions & Scenarios (A&S) Document. 

Key decision, D.07-12-052 (LTPP Decision) and D.13-10-040 (Energy Storage Procurement Framework Decision) set requirements for the IOUs in order to enter into a utility-owned contract. D.07-12-052 determined that the IOUs must first show that holding a competitive RFO is infeasible and provided five categories of exceptions with requirements for making this showing that are unique to each category - i.e., market power mitigation, preferred resources, expansion of existing facilities, unique opportunity, and reliability. The CPUC will determine exceptions for utility ownership outside of the competitive process in these five categories on an individual case-by-case basis through an IOU application.  

On June 23, 2016, D.16-06-042 was approved that closed this proceeding and transferred the one remaining unresolved set of modeling methodology issues to the successor Integrated Resources Planning (R.16-02-007) proceeding. 

2012 LTPP Authorizations

2012 LTPP Authorization for LCR in SCE's LA Basin

The CPUC issued an LTPP decision ordering SCE to procure between 1,400 and 1,800 MW of energy resource capacity in the LA Basin to meet long-term local capacity requirements (LCR) by 2021. Of this amount, at least 50 MW was required to be procured by SCE from energy storage resources, as well as up to an additional total of 600 MW of local capacity required to be procured from preferred resources - including energy storage resources. 

2012 LTPP Authorization for Local Capacity Requirements (LCR) in SDG&E

For SDG&E, the CPUC issued an LTPP decision directing the procurement of 500-800 MW, which includes 25-200 MW of energy storage, in its service area to meet long-term local capacity requirements (LCR) by the end of 2021. 

SCE 2013 Local Capacity Requirements RFO - Western LA (A.14-11-012)

On November 21, 2014, SCE filed its Western LA LCR RFO Results Application (A.14-11-012) seeking approval of contracts with selected bidders in its 2013 LCR RFO, which included a minimum procurement target of 50 MW for energy storage. The results showed that SCE had procured five times its minimum requirement in the first-ever utility procurement of energy storage in an all-source solicitation. CESA submitted comments and testimony supporting the RFO results.

On November 19, 2015, the resulting contracts were approved in D.15-11-041, but denied six NRG contracts because they relied on natural gas-fired backup generation to reduce the amount of energy served by the grid, which did not constitute either Demand Response (DR) or Preferred Resources. It also authorized, but did not require, SCE to procure additional Preferred Resources as required by the original authorizing decisions. The seventh NRG DR contract with was approved because NRG offered to amend its contract to preclude use of behind-the-meter fossil-fueled backup generation.

On December 21-24, 2015, four parties (Los Cerritos Land Trust, Sierra Club, EnerNOC, and Powers Engineering) submitted Applications for Rehearing of D.15-11-041, which has held up the approved contracts above. 

On June 1, 2016, the CPUC denied rehearings (D.16-06-053) and ordered SCE to procure an additional 169.4 MW of preferred resources or energy storage, per the requirements of D.13-02-015 and D.14-03-004.

On July 1, 2016, two of the four parties that filed Applications for Rehearing subsequently filed a Petition with the California Court of Appeals (see Powers Engineering, et al. vs. CPUC). The Petition asserts that the CPUC failed to proceed “in the manner required by law,” discriminated against preferred resources and energy storage, and abused its discretion when it refused to consider whether changed circumstances would serve to lower the need for gas-fired generation. The petitioners argued that SCE failed to meet the minimum preferred resource and energy storage requirements, even as its bid analysis showed preferred and energy storage resources were available and cost-effective. 

On September 1, 2016, the Court of Appeals summarily dismissed the Petition. However, the Petitioners have been allowed to submit a late-filed Petition to the California Supreme Court. 

On November 30, 2016, the California Supreme Court denied a review of the Petition from Powers Engineering. This likely concludes the legal challenges of this procurement, unless Powers Engineering petitions the US Supreme Court by February 28, 2017. 

SCE 2013 Local Capacity Requirements RFO - Moorpark (A.14-11-016)

On February 13, 2013, D.13-02-015 ordered SCE to procure a minimum of 215 MW and a maximum of 290 MW of electrical capacity in the Moorpark sub-area to meet identified long-term local capacity requirements by 2021. This need existed in large part due to the expected retirement before 2021 of once-through-cooling generation facilities located in Oxnard, CA.  

On November 26, 2014, SCE filed a separate Moorpark LCR RFO Results Application (A.14-11-016) seeking approval of contracts with selected bidders in its 2013 LCR RFO, which included solar and energy storage projects.

On May 26, 2016, a Decision (D.16-05-050) was issued that approved six contracts for energy efficiency (6 MW) and two contracts for renewable distributed generation (5.66 MW). D.16-05-050 also approved the 20-year NRG contract for 262 MW of gas-fired generation (Puente Project) while deferring the consideration of the 10-year NRG California South refurbishment agreement for the existing 54-MW Ellwood Generating Station (along with an attached 0.5 MW energy storage contract) to a subsequent decision in order to develop the record and determine if there is a reliability need that it would meet. The Ellwood contract was determined to exceed the maximum amount authorized under D.13-02-015 and was not considered an incremental resource. The refurbishment would extend the life of the plant by an additional 30 years to 2048 and is intended by SCE to provide 54 MW (out of the 105 MW) of capacity needed to avoid an N-2 contingency during the loss of the Goleta-Santa Clara 230-kV transmission line.

On June 30, 2016, the Center for Biological Diversity (CBD) filed an Application for Rehearing contending that the CPUC acted beyond its jurisdiction and that the Decision’s findings are not supported by the record (e.g., violating the loading order, demonstration of need). CBD also argued that the California Environmental Quality Act (CEQA) review should have preceded CPUC action. 

On July 1, 2016, the California Environmental Justice Alliance (CEJA) and Sierra Club jointly filed an Application for Rehearing focused on the legal error of not considering environmental justice in procurement decisions and on the requirement to await the CEC's environmental review before CPUC action.

On December 1, 2016, an Order was issued that denied the applications for rehearing of D.16-06-050 focused on the procurement of the Puente contract due to environmental justice issues being one of many needs to be addressed, among other reasons cited. 

On August 16, 2017, the CAISO Moorpark subarea local capacity special study was published regarding alternatives to the Puente Power Project, which is undergoing CEC environmental review. The CAISO analyzed three portfolios of local capacity alternatives in the absence of Puente, but did not address the timing or feasibility for procurement of the alternative resource portfolios. The three alternative scenarios include a 135-MW baseline of incremental DERs that consists of 80 MW of storage-enabled DR, 25 MW of solar-plus storage resources, and 30 MW of existing slow-responding DR resources coupled with incremental energy storage. The baseline alternative scenario was not found to be sufficient to meet the local capacity requirements. The additional “grid-connected” resources needed to meet the local capacity technical study criteria for each of the three scenarios are detailed below:

• Scenario 1: 125 MW of IFOM energy storage resources with 9-hour continuous discharge duration would be necessary to satisfy local capacity requirements consistent with the local capacity technical study criteria.

• Scenario 2: A 240 Mvar reactive power device would be necessary to satisfy local capacity requirements consistent with local capacity technical study criteria. Unlike Scenario 1 and 2, however, the reactive support does not also provide protection from loss of load through load shedding to avoid thermal overloads; load shedding is not desirable but is permitted under the local capacity technical study criteria in the circumstances being studied.

• Scenario 3: If the 54 MW Ellwood Generating Facility is retired rather than refurbished, 240 MW of energy storage resources would be necessary to satisfy local capacity requirements consistent with the local capacity technical study criteria. 115 MW of this energy storage capacity would need 5-hour continuous discharge duration, 65 MW would need 9-hour continuous discharge duration, and 60 MW would need 10-hour continuous discharge duration.

CESA relayed its appreciation and support for the CAISO’s study, perhaps the first of its kind where an ISO evaluated energy storage as an alternative to traditional power generation or infrastructure, but recommended a reexamination of the energy storage costs used and how a competitive solicitation is the best means to obtain real cost information. Such outdated cost assumptions are likely the drivers for why energy-storage-based alternative portfolios resulted in such high comparative costs. Specifically, CESA contested some of the methodologies and assumptions used:

• With more BTM PV, the peak of the load curve narrows and thus allows shorter-duration energy storage to meet underlying local capacity needs in the future, in contrast to the 9-hour duration tested in the study

• The CAISO’s use of $1,940/kW ($485/kWh) by 2020 for a 4-hour system is on the high-end of the range predicted by other sources, such as EPRI, GTM, and ESA, which predict lower costs in 2016

• The CAISO inappropriately scales the costs for a 4-hour system linearly to a 9-hour system

• The CAISO does not factor all the other benefits of energy storage and thus understates the full range of benefits

• Additional consideration of the role and capabilities of BTM energy storage is needed, including how it is unfair to measure the full costs of these systems that are already deployed

See CESA's comments on August 30, 2017 on CAISO's Loacl Capacity Alternatives Analysis.

On September 14, 2017, evidentiary hearings were held. CESA will not provide testimony given the focus of these evidentiary hearings on the permitting decision for the Puente project. Following some backlash on cost assumptions used in the study, the CAISO submitted post-hearing comments in support of preferred resource alternatives, with a new expedited RFO to determine economic feasibility. The new local capacity resources would need to be in place and operational prior to the summer 2021 peak-load period. Subsequently, the CEC Committee issued a statement recommending against the approval of the project because it is “inconsistent with several Laws, Ordinances, Regulations, or Standards” and will “create significant unmitigable environmental effects". Meanwhile, NRG Energy, the developer of the project, asked the CEC to end hearings over its proposal as it reviews whether or not to withdraw its application, following the comments and statements made by the CAISO and the CEC. NRG subsequently asked the CEC to suspend its application for the proposed Puente project for six months, while it works with SCE to determine if preferred resources could replace the 262 MW project.

On September 28, 2017, D.17-09-034 was issued by ALJ De Angelis that rejected the 10-year, 54-MW Ellwood Generating Station to give the CPUC additional time to explore whether any approved need in the Santa Barbara/Goleta area can be met in a manner more consistent with the CPUC’s goals of reduced reliance on fossil fuels. The 30-year refurbishment Ellwood contract and 0.5 MW energy storage contract (linked to the Ellwood contract) are thus rejected because there is no reliability-based urgency and due to the CPUC’s preferences to have SCE conduct an all-source solicitation to consider clean energy alternatives, rather than to extend the life of a gas-fired plant for an additional 30 years. The CAISO identified the local capacity need to be 29.6 MW without Ellwood. The reasons provided in the decision include the following on how Ellwood may not be the ‘optimal’ solution:

• The low and unknown probability of an N-2 contingency due to the loss of the Goleta-Santa Clara 230-kV transmission lines

• The potential to drop load during an N-2 contingency

• Existing air permits by Santa Barbara County Air Pollution Control District that restrict and limit Ellwood’s operations to perform short circuit duty and during an N-2 contingency

• Planned upgrade of the Santa Clara 66-kV distribution system minimizing the need for Ellwood

Energy storage procurements may result from this decision. SCE described how the process would unfold if it had to run a new solicitation seeking another portfolio of LCR resources targeting the Moorpark Sub-Area. SCE also explained how it attempts to solicit participation of various types of resources, as well as the challenges related to attempting to procure resources with specialized reliability characteristics, in a short amount of time. SCE noted that among those challenges is the effect on customer costs. Such cost pressures arise not only from the compressed timeline of a new solicitation, but also from the disruption of established procurement processes. SCE also described the results of other recent SCE solicitations (i.e., RPS, 2016 Energy Storage RFO) expressing a preference for specific areas, like Goleta, and noted that it could not tell what kind of portfolio would emerge to fill the Moorpark Sub-Area need if SCE conducted a new solicitation. One concern seemingly presented by discussion in the decision is that the CPUC may be entertaining the idea of prohibiting offers that combine existing generation with incremental energy storage capacity going forward. The decision discussed the CPUC’s procurement rules, which are intended to “prevent market distortions and ensure a level playing field among bidders”. This may be an issue that CESA targets going forward as there are potential cost-effective energy storage retrofit opportunities.

On November 27, 2017, the CPUC directed SCE to submit a Moorpark sub-area LCR procurement plan to the CPUC’s Energy Division for review given that the Puente Project was put on suspense and the Ellwood contract was rejected in a decision.

On December 21, 2017, SCE filed its Moorpark Procurement Plan. The OTC unit retirements, the retirement of several other thermal plants (e.g., Ellwood, Mandalay #3) in the Moorpark sub-area, and the contingency of losing the three Moorpark-Pardee 230-kV lines has created a 318 MW LCR deficiency by 2022, according to the CAISO’s Moorpark Sub-Area Local Capacity Alternative Study in August 2017. The 10-MW of energy storage contracted under its 2016 ES&DD RFO has reduced that LCR deficiency to 308 MW. Part of this RFP will focus on resiliency in the Santa Barbara/Goleta area, which is exposed to a prolonged 230-kV N-2 contingency that could result in extended outages, but it will count towards the Moorpark LCR need as well. There are two Goleta-Santa Clara 230-kV transmission lines being the only points of connection between Goleta and Santa Barbara with the rest of the SCE transmission system. These lines are at risk of loss due to its towers being located on mountainous terrains that are at higher risk of wildfires and mudslides and require significant time to repair in the event of a disaster. The total LCR MW need is reduced to 76 MW with SCE’s proposed Moorpark-Pardee No.4 230-kV circuit. SCE noted that the fourth line will address voltage collapse issues upon loss of the first three lines.

Dependent on the RFP portfolio mix, energy storage with discharge durations of 4 hours and greater than 9 hours may be required to fully satisfy the LCR need. Given that there is insufficient generation available during an N-2 event to charge additional energy storage during off-peak hours due to the limited capacity of the adjacent 66-kV sub-transmission lines in Santa Clara, energy storage bidders will need to consider or identify a generation source (e.g., peaker, fuel cells, and/or solar). The adjacent sub-transmission lines can re-route about 100 MW to the Santa Barbara/Goleta area in the event of an outage within one hour, with a planned upgrade in May 2019 expected to increase this backup capacity to 180 MW, but it still falls short of the 285 MW forecasted annual peak load and these lines do not provide adequate short circuit duty. As a result, SCE indicated that it will consider proposals for small (less than 55 MW) gas-fired generation projects connected to the Goleta system due to potential charging constraints as mentioned above, even as it provides a greater preference for preferred resources and energy storage to meet a 105 MW shortfall.

The differences between the terminated Goleta RFO and this new RFP are highlighted below:

Eligible BTM and IFOM resources must be electrically connected at or downstream of: Santa Clara 220/66kV Substation (preferred resources only), Goleta 220/66kV Substation, and Moorpark 220/66kV Substation (preferred resources only). SCE is looking for new (incremental) resources with year-round delivery from proven, commercialized technology, and/or configurations and from offerors must be experienced developers. Contract terms by delivery period and minimum offers can vary by type of product, summarized below:

CESA supported SCE’s plan but recommended that this solicitation should operate in line with the Commission's determinations of need and should not assume incremental or unapproved transmission solution reduce the need. Additional information on how energy storage resources can address voltage collapse issues would support non-wires transmission alternatives. CESA also requested that the definition of incrementality should be expanded to ensure the best outcome for ratepayers.

See CESA's informal comments on January 16, 2018 on the SCE Moorpark Procurement Plan.

On February 2, 2018, the CPUC approved SCE’s procurement plan with minor modifications. In response to stakeholder comments around its consideration of new gas-fired generation in the solicitation and in alignment with SB 350, SCE modified its solicitation to actively seek and express a preference for renewable and GHG-free resources in disadvantaged communities. SCE also clarified that it may approve contracts that do not have the highest net present value (NPV) based on these preferences.

On March 22, 2018, since the CAISO Board approved SCE’s proposed Moorpark-Pardee Line No. 4 transmission line, SCE revised its RFP to no longer seek projects interconnected at or electrically downstream of the Moorpark 220/66 kV substation.

On April 9, 2018, the Big Creek/Ventura Local Area LCR Study Results were released, leading SCE to revise its LCR MW target for this RFP to 80 MW to 90 MW, up from the 76 MW to 86 MW in the initial RFP documents, which accounts for the approved transmission line. SCE also clarified that its Goleta resiliency objective remains unchanged at 95 MW.

On May 15, 2018, the CAISO’s Santa Clara Sub-Area LCR study results were issued that led SCE to revise its LCR need in this solicitation to between 102 MW and 164 MW, up from the previous range of 80 MW to 90 MW. If more resources are selected in the Goleta area, SCE explained webinar that it may solicit for MW closer to the lower end of the new range, whereas if more resources are selected in the Santa Clara area, SCE may solicit MW closer to the higher end of the new range. The new Goleta-specific LCR need was revised to 15 MW to 25 MW, though SCE may still procure beyond this LCR need due to its resiliency objective. In addition, after further consultation with the CAISO, SCE revised the initial delivery date requirement to March 1, 2021 (instead of the previous January 1, 2021 requirement), though SCE will place a preference for bids with initial delivery prior to September 1, 2020. There have been a number of other miscellaneous changes, including the ability for DR resources to offer 20-year bids and the revised 8-hour duration need from 2pm to 10pm (formerly published as a 10-hour duration need).

On June 1, 2018, SCE circulated a market notice that notified participants that it will extend the initial offer deadline from June 21, 2018 to July 3, 2018 to give bidders additional time to consider recent changes to the RFP. SCE also posted new pro forma contracts and RFP instructions. However, SCE explained that the later initial offer deadline will not change the various milestones for final bid selection and filing for CPUC approval of contracts. The new RFP materials reflected some changes related to D.18-01-003 – also known as the Energy Storage MUA Decision. SCE developed an online offer form that will require energy storage bids to fill out a questionnaire that identifies the services to be solicited by SCE on the one hand and informs SCE of services currently being offered or will be offered by the energy storage resource outside of this solicitation. It is unclear on how the responses to this questionnaire will be used for evaluation purposes.

PG&E 2018 Oakland Clean Energy Initiative (OCEI)

PG&E, in collaboration with East Bay Community Energy (EBCE), is seeking innovative clean energy project proposals to meet local transmission reliability needs in this competitive solicitation called the Oakland Clean Energy Initiative (OCEI). As part of the 2017-2018 TPP, PG&E proposed a combination of substation upgrades and preferred resources to address the OCEI need absent local fossil-fired generation. The OCEI RFO focuses on the development of such preferred resources to mitigate contingency overloads in the local sub-area.

PG&E will procure resources to meet transmission reliability needs, and EBCE will procure the associated RA capacity, energy and renewable energy credits (RECs). PG&E is seeking EPC offers for up to 20 MW (120 MWh) of utility-owned energy storage capacity, with minimum offer sizes of 5 MW (20 MWh) and a maximum of 20 MW (120MWh). Any system duration may be considered for third-party-owned energy storage offers, with the evaluation based on how many MW and hours the resource contributes to meeting the overall need. For utility-owned projects, PG&E is providing space within two existing substations for the construction of energy storage facilities, where PG&E will provide interconnection facilities at the Oakland C and L substations. Projects must be online or installed by February 1, 2022.

On May 8, 2018, the RFO protocol was updated to modify the maximum project size for energy storage offers as 80 MWh (instead of 10 MW). PG&E also added additional RFO documents, including third-party offer forms and utility-owned offer forms. All the solicitation documents can be found here.

In recent Q&A responses to bidders, PG&E clarified that DR is only eligible to participate in this RFO if it utilizes energy storage and participates in the CAISO market and that the Oakland Power Plant is also eligible to offer into the RFO as an incremental resource if it is repowered or reconfigured in a way that meets the eligibility requirements. Additionally, PG&E clarified that any SGIP-funded resources that have not submitted an SGIP program application after April 13, 2018 (i.e., the date of this RFO) would be considered incremental and eligible. Finally, since proposed projects will be bidding both RA capacity to EBCE and a market-participating transmission resource to PG&E, PG&E explained that a hypothetical 20-MW energy storage project cannot offer the same 20 MW capacity to EBCE and PG&E to address the same need. In other words, there has to be capacity differentiation of the 20-MW resource, pointing to the MUA rules adopted in the Energy Storage proceeding.

SDG&E 2014 All-Source LCR RFO

The 2012 LTPP Track 4 Decision (D.14-03-004) established an LCR need of 800 MW of electricity capacity by the end of 2021. D.14-03-004 also set a minimum procurement requirement for 25 MW of energy storage and 175 MW of preferred resources, as well as a maximum authorization of 600 MW for conventional resources.

On May 21, 2015, the CPUC conditionally approved SDG&E's Application (in D.15-05-051) to enter into a power purchase tolling agreement (PPTA) with the Carlsbad Energy Center (a natural gas-fired, simple-cycle peaking generating facility located adjacent to the existing Encina Power Station) to fill 600 MW of its LCR needs for 20 years, which has an expected online date of November 1, 2017. Approval of the Application is subject to two conditions: (a) that the project capacity is reduced to 500 MW while otherwise subject to the same per-unit price, terms, and conditions; and (b) that the 100 MW in residual procurement authority resulting from the amendment of the PPTA must consist of preferred resources or energy storage. 


On November 5, 2015, the CPUC denied Applications for Rehearing of the Carlsbad PPTA. 

On December 7, 2015, Protect Our Communities (POC) and Center for Biological Diversity (CBD) appealed the CPUC’s Decision on Rehearing of the Carlsbad PPTA at First Appellate District of the California Court of Appeals.

On March 31, 2016, SDG&E announced that it signed a contract with Hecate Energy, LLC for a 20-MW energy storage facility, in addition to 18.5 MW of energy efficiency projects. SDG&E justified its under-procurement of energy storage by stating that it would rather take a ‘measured’ approach and that it had difficulty developing a ‘robust’ energy storage contract.

After outreach and discussions with SDG&E, CESA ultimately called for this RFO to be expanded or re-run via a protest, which focused on serious shortcomings of SDG&E’s contracting levels and approach.

See CESA's protest on May 6, 2016 on SDG&E's Application for Approval.

On May 16, 2016, SDG&E submitted a reply to CESA's protest, saying that the terms were fairly agreed to between two parties, that it has the best interest of its customers, and that additional energy storage will be procured in future RFOs.

On June 9, 2016 and August 12, 2016, prehearing conferences (PHCs) were held on SDG&E's Application to approve the Hecate contract. Throughout this Application review process, CESA has focused on three points. First, the Hecate contract is not enforceable if SDG&E can arbitrarily terminate it. Second, energy storage bids should not be rejected based on speculative future pricing, but instead be accepted based on current cost-effectiveness. Third, SDG&E should not condition acceptance of bids based on regulatory outcomes (e.g., TOU) in unrelated CPUC proceedings.

See CESA's opening brief on September 9, 2016 on SDG&E's Application for Approval.

On September 23, 2016, SDG&E filed its reply brief, revealing that SDG&E decided to exercise its option to terminate its 20-MW energy storage agreement with Hecate. Among the reasons for coming to this decision is that SDG&E received more favorable energy storage and other preferred resource offers in its 2016 RFO. SDG&E also acknowledged that it will no longer apply the TOU contingency provision to comply with D.16-09-007, the decision approving the energy storage procurement framework for the 2016 cycle. In September 9 CESA had previously argued against conditioning acceptance of bids based on regulatory outcomes in unrelated CPUC proceedings. Essentially, what CESA warned against played out. In future procurements, CESA will continue to argue that bids cannot be rejected based on speculative future pricing (instead of being accepted based on current cost-effectiveness) and how option provisions are not acceptable contracts. 

On September 14, 2016, California's First Appellate District of the California Court of Appeals accepted the Petition jointly filed by POC and CBD to review the CPUC's approval of the Carlsbad PPTA. The lawsuit focuses on the lack of a transparent, public bidding process and how more renewables and energy storage should have been procured to meet the demand.

On December 15, 2016, D.16-12-041 was issued that approved the Application that still included an energy efficiency contract with Willdan Energy Solutions but does not include the 20-MW energy storage agreement with Hecate. The CPUC sided with SDG&E in finding that deferring procurement of energy storage to 2021 is allowed and preserves flexibility in procurement timing. 

SDG&E 2016 Preferred Resources LCR RFO

On February 26, 2016, SDG&E published its RFO seeking preferred resources to meet its LCRs established in D.14-03-004 (Track 4 Decision). SDG&E was soliciting offers for up to 140 MW of preferred resources, which includes energy efficiency, DR, renewables, distributed generation and energy storage. SDG&E was soliciting third-party owned, contracted resources for all preferred resources product types with the exception of energy storage. For energy storage, SDG&E was soliciting third-party owned contracted resources, and energy storage systems to be owned by SDG&E. Specific eligibility requirements, participation criteria and evaluation methodology for each resource type can be found here.  Other RFO requirements include:

• Local RA requirements must be met (i.e., discharge for three consecutive day, four hours per day)

• Qualitative consideration will be given to projects that can count as Category 1 Flex RA

• Preference will be given to projects starting as early as 2018

• All contract lengths will be considered except that a portion of the offered delivery term must occur in 2022

• Phase 1 interconnection study must be completed and site control must be demonstrated

• Land acquisition, permitting, financing, and construction must all be demonstrated through plans and documentation

• Capacity must be guaranteed through a warantee

• O&M services must be priced through the end of the expected useful life of the equipment

• No minimum amount of annual cycles is required but priority will be given to those capable of at least 50 cycles per year

• DR resources must be a supply-side resource and thus have 500 kW in aggregate minimum resource capacity

On July 1, 2016, the RFO closed to offers. Bidders offering utility-owned projects were required to submit their complete offers six weeks prior to the RFO closing date to allow for a pre-evaluation screening criteria of the bidder's development experience in order to minimize overall ratepayer risks. 

On March 30, 2017, the contracts were fully negotiated and executed. SDG&E sought the following types of contracts:

• Power Purchase Tolling Agreement (PPTA): This structure mimics a traditional tolling agreement whereby the developer is paid a monthly capacity payment for the term of the contract, and SDG&E procures the project's charging electricity and arbitrages the project's energy value. The size parameters were 0.5-140 MW.

• Build, Own, and Transfer (BOT): The project is constructed on developer-owned land with all permitting, interconnection, and construction activities conducted by the developer, while SDG&E takes ownership of the project and underlying land upon successful project commissioning. The size parameters were 10-140 MW.

• Engineering, Procurement, and Construction (EPC): The project is constructed on SDG&E-owned land, with the construction activities falling on the developer and the parties sharing permitting and interconnection responsibilities. The size parameters varied by location.

On April 19, 2017, SDG&E filed an application for approval for 83.5 MW of energy storage contracts (plus a 4.5-MW contract for demand response) to fulfill a local RA need to replace the output from the retirement of the San Onofre Nuclear Generating Station (SONGS). The approximate cost of the six contracts is reported to be $235 million. Combined with the 37.5 MW procured from the Aliso Canyon emergency procurement and the EE/DR contracts in this RFO and in the 2014 All-Source RFO, SDG&E has met its 144-MW procurement requirement. SDG&E said it received approximately 240 energy storage bids. 

There were several interesting insights that could be gleaned from SDG&E’s application and prepared testimony:

• Several very large projects (100 MW or more) were not selected because they would “overly concentrate risk” its portfolio

• Several conforming bids that offered RA-only were not selected because of the constantly changing nature of RA

• The two winning utility-owned projects had Net Market Values (NMVs) that were 45% higher than the most cost-competitive shortlisted third-party-owned projects because utilities retain all value that remains after the duration of the contract

• Utility-owned projects have the advantage of reduced development risk and have increased optionality from changing regulatory rules

• SDG&E believes that DR should be procured via all-source RFOs because they result in lower capacity prices as compared to those in the Demand Response Auction Mechanism (DRAM) pilots

• No locational effectiveness factors were used because the CAISO determined that all generation units had the same locational factors according to its 2016 Local Capacity Technical Analysis

SDG&E proposes to recover the costs of energy storage resources using the Local Generation Charge on a non-bypassable basis. The remaining authorization target per the Track IV Decision (D.14-03-004) is 56 MW of preferred resources or energy storage. SDG&E has procured its minimum 165 MW pursuant to D.13-10-040 but still must procure 7.5 MW to meet its minimum customer domain target.

On September 25, 2017, a Scoping Memo was issued to determine the issues of this proceeding, including the reasonableness of the costs, process, and need of the proposed contracts, along with whether the contracts meet certain key statutory requirements concerning energy storage systems. 

On October 20, 2017, opening testimony was served. ORA recommended that the CPUC require SDG&E to explain why its RFO results were limited to lithium-ion-based batteries. If SDG&E does not provide a reasonable explanation, ORA recommends that the CPUC deny cost recovery associated with the utility-owned energy storage projects given the size of these projects. For the Miramar energy storage facility proposal from RES Americas, ORA recommendedthe denial of this contract as it finds the cost to be not just and reasonable as required by PU Code Section 451. ORA expressed its doubts about the project not being able to be cycled economically due to the “high cost of the cycle degradation fee” being greater than the revenue generated by the resource, as it provides RA and ancillary services. ORA is concerned that the RFO results do not demonstrate technological neutrality consistent with D.14-03-004 since the RFO requirements had limited the solicitation to lithium-ion battery technologies.

On October 30, 2017, SDG&E served its rebuttal testimony that explained that the RFO was not limited to only lithium-ion batteries and was open to all preferred resources and storage technologies as required by D.14-03-004. The top ranking bids were lithium-ion projects that provided the superior economic value, according to SDG&E.

On January 5, 2018, an opening brief was filed by ORA recommending that SDG&E should delay the RES contract to take advantage of declining battery storage costs. Specifically, ORA asserted that the project is coming online two years earlier than is required by capacity need in 2021.

On January 19, 2018, ORA submitted a reply brief indicating that it believes that the issue of SDG&E’s RFO being limited to lithium-ion technologies has been clarified and resolved. SDG&E, meanwhile, argued that the Miramar project had a positive NMV and is thus cost-effective. 

On April 25, 2018, a PD was issued, with comments from ORA seeking corrections on the characterizations of its previously-held positions in the findings of fact.

On June 7, 2018, D.18-05-024 was issued that approved six energy storage contracts totaling $235 million and 88 MW of local capacity:

• RES will build a 30 MW/120 MWh utility-owned lithium-ion battery storage facility in San Diego to be completed by December 2019.

• AMS will build a 4 MW/16 MWh third-party-owned lithium-ion battery storage facility in San Juan Capistrano to be completed by December 2019.

• Fluence will build a 40 MW/160 MWh utility-owned lithium-ion battery facility in Fallbrook to be completed by March 2021.

• Powin Energy will build a 6.5 MW/26 MWh third-party-owned lithium-ion battery storage facility in Escondido to be completed by June 2021.

• Enel Green Power will build a 3 MW/12 MWh third-party-owned lithium-ion battery storage facility in Poway to be completed by December 2021.

• OhmConnect will provide a DR program for the equivalent of 4.5 MW.

The only contract that was contested was RES’ Miramar BESS Project, a 30-MW, four-hour lithium-ion battery storage system, but the decision rejected ORA’s position that the contract should be rejected for only considering lithium-ion battery projects since the PD found that SDG&E sufficiently conducted a technology-agnostic solicitation. The decision also agreed with SDG&E that the Miramar BESS Project is cost-effective due to the positive net market value, similar to the five other energy storage contracts, and that it is not prudent to postpone procurement until the very end of the compliance period due to potential project drop-outs and delays. Importantly, the decision noted that SDG&E may only count 38.85 MW of utility-owned storage toward its AB 2514 energy storage targets as determined in D.13-10-040.

Climate Adaptation (R.18-04-019)

Background

On May 7, 2018, motivated by statewide policy directives, recent climate events, and advancements in climate science and tools, an OIR was issued that adopted a rulemaking to consider strategies and guidance for climate change adaptation. Phase 1 of this proceeding will address how electric and gas utilities define climate change adaptation, identify tools and data for planning and operations related to climate adaptation, identify risks facing vulnerable communities and DACs with respect to climate change impacts, and develop guidance to incorporate climate change adaptation into planning and operations.

On October 10, 2018, a Scoping Memo issued on October 10 specified a Working Group structure to work through these Phase 1 issues and questions. CESA is tracking the discussions around the definition and value of “resilience” in this proceeding, which may have important implications across other proceedings involving storage.

Definitions

On January 25, 2019, a Ruling was issued publishing the final Working Group Report on the definition of “climate change adaptation” for the utilities. The CPUC staff proposed a definition to focus on climate-driven risks to safety, reliability, affordability, and resiliency in utility operations. The report included consensus on the need to distinguish between the terms “adaptation” and “resilience” but consensus was not reached on whether reliability should be separate from the discussion of adaptation. In comments, the IOUs discussed how the definition for “resilient” within the context of the proposed definition of climate adaptation should not only focus on “extreme events” but also on climate impacts that are gradual or incremental. CESA is tracking the discussions around the definition and value of “resilience” in this proceeding, which may have important implications across other proceedings involving storage.

On November 1, 2019, D.19-10-054 was issued that addressed the definition of climate adaptation for utilities (Topic 1). Specifically, “resilient” means able to withstand extreme and incremental events and the ability of utility systems to recover when a disruption occurs. The Safeguarding California definition should be used as the CPUC’s hybrid definition of climate change adaptation (i.e., “refers to adjustment in utility systems using strategic and data-driven consideration of actual or expected climactic impacts”). Many parties were generally supportive of the decision. Small and low-income community representatives, however, sought to shift the definition and data sources to focus more on climate change impacts to communities and broadly to human impacts, not just on utility operations.

Data Sources, Models, and Tools

On January 8, 2019 and February 4, 2019, working group meetings were held to review the data sources, models, and tools for adaptation analyses that would meet the “evidentiary standards” for IOU planning. Regulators and policymakers presented on the need to use public-domain datasets that are replicable, peer-reviewed, granular in geographical and temporal resolution, and preferably adopted in official state guidance documents. The IOUs also presented on the common available data utilized by the IOUs for their system planning and operations. The differences in utility approaches were driven by specific topography and historical system buildout. SDG&E highlighted how its own climate adaptation assessment found that most of their at-risk assets were at the distribution, not transmission, level and located in low-lying coastal hazard areas. In response, SDG&E installed wave-current sensors to predict water levels.

On March 15, 2019, a Ruling was issued that attached the Final Working Group 2 Report that presented consensus proposal concepts on several data sources, modeling, and tools to inform climate adaptation strategies, including the necessity of considering forward-looking weather and climate data and the incorporation of climate change considerations that are flexible enough to account for the evolving nature of science. Near consensus was reached on the management of climate data updates for IOU planning and the use of Cal-Adapt as a high-quality repository of climate information for California. The working group could not agree, however, on the duties and logistics of the new Technical Advisory Group to review and assess climate data for potential IOU use or on the use of the IOUs’ proprietary data and analysis for planning.

On November 1, 2019, D.19-10-054 was issued that addressed climate adaptation data sources, models, and tools (Topic 2). Specifically, energy utilities should use the forward-looking climate scenarios and projections used in the most recent Statewide Climate Change Assessment (i.e., Representative Climate Pathways [RCP] 8.5 in their planning activities) when analyzing climate impacts, risks, and vulnerability of utility systems, operations, and customers. Many parties were generally supportive of the decision. Small and low-income community representatives, however, sought to shift the definition and data sources to focus more on climate change impacts to communities and broadly to human impacts, not just on utility operations. Meanwhile, the IOUs wanted clearer linkages to how utility planning, investment, and operational activities would directly apply to specified climate data, models, and tools.

Utility Planning Guidelines

On May 15, 2019, a Staff Proposal was published that laid out the principles for community engagement on investment decisions and proposed that the IOUs undertake additional analysis (beyond what they have already done) that determines the location of vulnerable communities and DACs that will be potentially affected by climate impacts to the IOU’s infrastructure and that determines the location-specific vulnerabilities and adaptive capacity of these communities that may have utility service curtailed due to climate impacts. Local governments are required to complete similar assessments by 2022 pursuant to SB 379, so the CPUC staff proposed that the IOUs work with the local governments on their own assessments.

On May 21, 2019, a working group meeting was held to discuss a process for identifying and prioritizing climate change adaptation investments and activities that benefit vulnerable communities and DACs.

Vulnerable & Disadvantaged Communities

On March 25, 2019, a working group meeting was held to discuss definitions for vulnerable and disadvantaged communities. While there are a number of statutory definitions of “disadvantaged communities”, there is currently no legislative direction in California on “vulnerable communities” in a climate adaptation context. There are, however, a growing number of public sector efforts to assess and adapt to climate impacts. For example, Executive Order B-30-15 requires all state agencies to incorporate climate into all planning and investment decisions. The CPUC staff recommended a definition for “vulnerable communities” that is consistent with the other definitions of vulnerability used by the State, including the Governor’s Office of Planning and Research and CAL FIRE. Specifically, the CPUC staff proposed the following: “Vulnerable communities experience heightened risk and increased sensitivity to climate change and have less capacity and fewer resources to cope with, adapt to, or recover from climate impacts. These disproportionate effects are caused by physical (built and environmental), social, political, and/ or economic factor(s), which are exacerbated by climate impacts.”

In an effort to be consistent with existing CPUC practice, staff proposed using CalEnviroScreen top 25% as a starting point for the definition of disadvantaged communities. CalEnviroScreen, however, is just one tool available to identify communities that are disadvantaged. Staff thus proposed expanding the definition of disadvantaged communities in order to include low-income communities in California that are not captured by CalEnviroScreen, as follows: (1) 25% highest scoring census tracts according to the CalEnviroScreen; (2) tribal lands; and (3) census tracts with median household incomes less than 80% area or state median income.

On June 25, 2019, a Ruling was issued that published the Topic 4 Working Group Report on climate vulnerable and disadvantaged communities. Overall, the working group generally agreed on the need for community input as a key consideration in defining climate vulnerability and disadvantage, but there was only partial consensus around certain recommendations and/or observations. For example, stakeholders disagreed on whether climate vulnerability and climate disadvantage are overlapping concepts, how climate disadvantage definitions could be confused with other existing programmatic definitions, and the need for clear roles and responsibilities for the proposed community engagement process.

In comments, most stakeholders were in support of the report’s findings and recommendations. The environmental parties recommended modifications to definitions to capture the spectrum of climate vulnerability as well as to cover gaps in the definition (e.g., tribes, rural communities); the IOUs, however, disagreed with defining all disadvantaged communities as climate vulnerable communities. The utilities expressed that the report should clarify how the utilities can only support climate adaptation to its energy infrastructure, so local governments may need to drive community engagement on broader climate vulnerability issues, but the environmental parties disagreed that the definition of vulnerability should be so narrow and should also consider access and rate impact issues (e.g., energy programs) as well as other sectors (e.g., water, transportation). They also requested more time to conduct the climate vulnerability assessment as well as clarifications on the desired level of granularity of the assessment. Both the environmental parties and the utilities recommended that climate vulnerability should either be linked to other CPUC proceedings or to investments made for reliability and resiliency.

On September 3, 2020, D.20-08-046 issued that directed IOUs to file vulnerability assessments every four years, pursuant to the Staff Proposal, to identify risks of climate change and options for mitigation. These operational risks include those related to wildfires, extreme heat, extreme storms, drought, subsidence and sea level rise, among other climate change phenomena. The key timeframe to be considered by the vulnerability assessment will be the next 20-30 years, but it should also include discussion on the intermediate (10-20 years) and long-term (30-50 years) assessments and risks. Disadvantaged vulnerable communities (DVCs), a new term arising out of this decision defined by being in the 25% highest scoring CalEnviroScreen tracts and having less than 60% of statewide median household income, were highlighted as being particularly vulnerable to climate change impacts and thus should be the focus of these assessments. To support these assessments, the decision creates cross-departmental climate change team at the IOUs. Notably, in the future, when IOUs sign new contracts for power, capacity or reliability, the IOUs will be required to take steps to identify climate change risks and obtain information from the operator. New long-term contracts of 15 years or more should include an acknowledgement in the contract that the operator has considered long-term climate risk.

In comments to the PD, the IOUs were generally supportive but requested some flexibility around time to prepare these assessments and clarity around roles and responsibilities. SDG&E, however, expressed concern with the new requirements for long-term contracts as increasing prices, losing transactions, and not being applicable to out-of-state resources. SCE added that they should only be required to contact existing operators who extend into the vulnerability assessment to have them assess climate risks – i.e., only being necessary for contracts that extend into 10-20 years and beyond. NRDC and PAO lauded the decision but recommended actionable items to ensure smart infrastructure decisions and to ensure studies are conducted in conjunction with Risk Assessment Mitigation Phase (RAMP) process for wildfire mitigation. While supportive, CEJA and the environmental justice groups took a more aggressive stance that the vulnerability assessments should occur every two years instead of every four years.

In response, the PD was revised to direct IOUs to host maps on their websites to identify the DVCs in their respective service territories and involve all DVCs in community engagement (not just those identified by the IOUs). Notably, the decision afforded the IOUs more flexibility on obtaining climate change risk information from power contracts, where the IOU must demonstrate in its vulnerability assessment that it exercised reasonable efforts to obtain it and provide the reason those efforts were unsuccessful.

Overall, this decision could expand the scope of infrastructure investments beyond those needed for load increase and wildfire mitigation, to one focused broadly on climate change impacts. To the degree that storage is immune to climate change impacts (e.g., which may not be the case for sea level rise), this may create a new class of opportunity for deferral projects by storage. Storage and DERs, however, are not explicitly called out. In addition, the introduction of DVN term may represent the highest class of “DAC” that could be relevant to other proceedings where such customer classifications are used to determine program eligibility and incentives. Finally, a new information submittal or attestation requirement may be needed for storage companies who contract with the IOUs for energy or capacity, recognizing that climate change impacts not just infrastructure but also generation supply. It is not yet determined whether this will actually directly impact procurement decisions in the future, but it may represent a burden for some resources with existing contracts.

Decision-Making Framework & Accountability

On November 14, 2019, a Ruling was issued that directed the IOUs to file any vulnerability assessments they have performed, or that have been performed for them on how they may adapt to climate change in the future by fortifying or altering its infrastructure to accommodate climate change. As part of Topic 5, the CPUC will develop a decision-making framework to make climate-related decisions under a high degree of uncertainty.

On November 15, 2019, a workshop was held to discuss the staff proposal and alternative approaches taken by SCE, California Department of Water Resources (DWR), and other consultancies. The CPUC staff proposal entailed three steps: (1) climate impact analysis in consultation with climate scientists; (2) infrastructure vulnerability assessment that reviews granularity, time horizon, sensitivity exposure, and adaptive capacity; and (3) community communication and proposal to the CPUC. Commissioner Randolph commented that this topic is intended to focus on vulnerability assessments being incorporated into long-term planning, with the recent emergency response issues being informative to the discussion but not to cause participants to lose sight of what is needed for long-term planning.

SCE contrasted its approach where it captures climate risks in two separate processes – i.e., capacity planning and infrastructure vulnerability assessments – that then lead to utility adaptation plans. Yet, SCE agreed with the staff proposal but highlighted that there are barriers to adaptation measures, including infrastructure standards that must be revised, including to operate systems under extreme conditions and to incorporate region-specific requirements based on vulnerability assessments. Rather than taking a system-wide approach, SCE recommended taking a climate risk factor to focus climate adaptation investments on high wildfire-risk districts. CPUC staff, however, responded that a system-wide look is needed to identify the high-risk areas. PAO added that climate adaptation should focus not only on infrastructure assets but also on rules and operations (e.g., PSPS), similar to what DWR presented as part of their climate adaptation strategies.

On January 29, 2020, a Ruling was issued that summarized workshop discussions, including how participants generally agreed that definitions should align with best practices to inform utility management of climate hazards, though the IOUs expressed concerns about how closely they must follow the process. The IOUs recommended that the climate adaptation assessments should be aligned with the Wildfire RAMP and GRC cycles as much as possible. The community impact analysis and the parameters of the vulnerability assessment, however, were identified as being unclear. In addition, stakeholders were unsure on how PSPS events should be factored into the vulnerability assessment and whether long-term time horizons should be included. Some parties went so far as advocating for all projects in IOUs’ GRCs above a certain amount should be subject to climate adaptation assessments, as well as include facilities that are not owned by the IOUs since utility decision-making may have led to outsourcing to third parties for key services and products.

PG&E Diablo Canyon Application (A.16-08-006)

Background

In collaboration with environmental and labor groups, PG&E plans to close its 2,240-MW Diablo Canyon Nuclear Power Plant (DCPP), which provides about 20% of PG&E’s and 6% of California’s electricity. PG&E will renounce plans to seek license renewals for Diablo Canyon’s two reactors, which expire in 2024 and 2025 respectively. The plant is being closed because of a combination of the 50% RPS by 2030, overgeneration management issues, low gas prices, stagnant load growth (due to efficiency and customer departure for CCAs), high fixed costs, high re-licensing costs (e.g., mandated retrofits), and safety concerns.

To replace Diablo Canyon's output, PG&E plans to procure a combination of renewable energy and energy efficiency, with costs to be recovered through non-bypassable charges. There are three key “tranches” to the deal:

• Tranche 1 is intended to achieve "early action" GHG savings prior to retirement. PG&E will seek 2,000 gross GWh in incremental energy efficiency by January 1, 2024, either through an RFO to be issued by June 1, 2018 or new utility-run programs. Costs will be recovered through the Public Purpose Programs (PPP) charge.

• Tranche 2 is intended to address the transition period after retirement of DCPP and provide certainty that GHG-free resources will replace some of DCPP output. PG&E will issue an RFO for an all-source solicitation for 2,000 GWh/year of GHG-free energy resources or efficiency by June 1, 2020 with deliveries between 2025-2030. Costs will be recovered through a newly-established Clean Energy Charge, with the option for CCA and DA providers to self-provide GHG-free energy resources in lieu of the Tranche 2 component of the Clean Energy Charge.

• Tranche 3 is intended to provide backstop procurement to ensure the RPS target is met. PG&E will pursue a voluntary commitment to reach a 55% RPS by 2031 and maintain this through 2045. Costs will be recovered through a newly-established Clean Energy Charge.

Tranche 2 does not include energy storage since “energy storage, by itself, is not a source of electricity.” However, if paired with generation, energy storage may be considered eligible as part of these solicitations. PG&E added that it will likely seek carbon-free energy storage resources, including pumped hydro and utility-owned energy storage, separately in the IRP proceeding. Furthermore, PG&E acknowledged that the “starting point” procurement commitment does not cover all the generation from Diablo Canyon, but if generation resources are insufficient, PG&E will come back to the CPUC for more procurement authority.

Application

On August 11, 2016, PG&E filed its Application for approval of the Joint Proposal submitted on June 20 (along with Friends of the Earth, Natural Resources Defense Council, Environment California, International Brotherhood of Electrical Workers Local 1245, Coalition of California Utility Employees, and Alliance for Nuclear Responsibility). The Application will next need to receive CPUC approval and will take a few years to finalize and implement closure and replacement plans. Parties envision that this issue will be addressed through the IRP proceeding given the long lead time before license expires. 

CESA focused its message on approving the orderly retirement of DCPP, while developing a process for determining the retirement capacity and energy in concert with steps to address ramping and other needs. Specifically, CESA commented that the lack of explicit inclusion of energy storage in the Application signaled that some of the challenge associated with renewable resource integration and DCPP retirement are insufficiently addressed.

See CESA's response on September 15, 2016 on PG&E's Diablo Canyon Application.

The Application proposes to have a Final Decision by no later than December 31, 2017. However, multiple parties across the spectrum protested the Application for various reasons – the main ones being that the Application circumvents the IRP and other CPUC processes, increases GHGs, unfairly proposes cost recovery through non-bypassable charges, and provides questionable economic/cost analyses. These reactions point to the contentiousness of this ‘backroom’ deal and may delay or prevent the approval of the Application.

On October 4, 2016, an All-Party Meeting was held to develop a schedule for the proceeding and reach consensus on issues that are in or out of scope. PG&E proposes to have all the relevant issues from its Application within the scope, but excludes land use, total economic impact, early retirement, and decommissioning as outside the scope of the proceeding. The ALJ proposed to include in the scope not only PG&E’s proposed list of issues, but also the timing of the shutdown, quantification of economic impact per SB 963, and land-use determinations. The ALJ also said that decommissioning of DCPP is premature without first seeking CPUC authorization, while PG&E said that its testimony is equivalent to an "LTPP showing". Additionally, many parties debated whether an interim process or the IRP would be appropriate for considering replacement power given the IRP procedural timeline and size of DCPP retirement. 

On December 8, 2016, PG&E held a workshop to clarify its proposal for replacement procurement of 25% of DCPP energy production, discuss the rationale for the proposed resource tranches, and elaborate on how PG&E determined its planning needs. There was a discussion around whether some or all of the replacement needs determination and procurement will be deferred to the IRP proceeding, and whether the planning horizon for the IRP proceeding would align with the replacement power needs by 2024. Questions were raised on how to ensure that energy efficiency procurement is incremental to program goals that have already been accounted for in the demand forecast. 

PG&E also presented on its proposed cost recovery through the Clean Energy Charge, which allocates costs to all bundled and unbundled electricity customers in PG&E territory, and its relationship with current bundled charges, such as the Power Charge Indifference Adjustment (PCIA) mechanism and the Nuclear Decommissioning Charge. Some parties who may face higher charges, such as CCAs, expressed concern and outrage regarding PG&E's proposal. 

Additionally, the CPUC staff presented 2014 Long-Term Procurement Plan (LTPP) study results that modeled one year of hourly grid operations with two cases (with and without DCPP) in 2024. The results showed a system capacity shortfall with DCPP and reduced renewable curtailment but higher emissions and production costs without DCPP (due to more dispatch of gas-fired generation in California and more dispatch of out-of-state coal). The CPUC staff noted that the results are not sufficient to forecast likely future grid conditions or drive procurement of replacement resources because it modeled only one fixed realization of the future and used outdated input assumptions.

On December 28, 2016, PG&E filed a joint motion requesting approval of a partial settlement that modified the Community Compacts Mitigation Program. 

On February 27, 2017, PG&E notified parties that it is down scoping this proceeding and withdrawing the Diablo Canyon Tranches #2 and #3 replacement proposals, as well as the proposal to implement the Clean Energy Charge to recover the costs associated with Tranches #2 and #3 “after careful review of the important feedback provided by parties in their January 27, 2017 opening testimony”. Notably, the Tranche #1 proposal and the requests for relief and cost recovery contained in A.16-08-006 remain intact. PG&E, along with the other parties in its Joint Application decided that the replacement for Diablo Canyon would be better addressed in the IRP proceeding (R.16-02-007).  Consistent with the Joint Proposal, PG&E is requesting the CPUC adopt a policy directive in this proceeding (A.16-08-006) that the output of Diablo Canyon be replaced with GHG-free resources as a part of the IRP proceeding. Parties in this proceed may still advocate for the adoption of Tranche 2, Tranche 3, and the Clean Energy Charge.

On March 17, 2017, rebuttal testimonies were heard on the Tranche #1 proposal and the requests for relief and cost recovery. Others testified against the withdrawal of Tranches #2 and #3 replacement proposals or against the DCPP retirement altogether.

On May 23, 2017, PG&E filed a joint motion requesting approval of a partial settlement that modified its original request for rate recovery of its NRC license renewal costs and its canceled projects. 

On January 11, 2017, D.18-01-022 was issued that approved PG&E’s plan to retire the DCPP in 2024 and 2025 when its federal Nuclear Regulatory Commission (NRC) operating licenses expire.  The decision rejected the $1.3 billion proposal (i.e., Tranche #1 proposal) for energy efficiency procurement to partially replace the output of DCPP given that “it is not actually clear that PG&E could actually procure over 50% more energy efficiency than a goal that is already supposed to include all cost-effective energy efficiency” and instead defered all replacement procurement issues to be addressed in the IRP proceeding. While CESA has previously advocated for early procurement of replacement resources, which would include energy storage in this application, this outcome is favorable relative to what was proposed in their revised application, which only sought approval for Tranche #1 of their application and not Tranche #2 and #3 of their application. Instead, it appeared that all replacement will be done through the IRP, which ensured that energy efficiency is not predetermined as a share of the replacement resources, thus opening greater opportunity for energy storage to compete to provide GHG-free resources. The decision also acted on more limited elements of PG&E’s proposal. First, it authorized rate recovery for up to $222.6 million (up from $160.5 million in the PD) for an employee retention program that is designed to provide incentives as needed for sufficient PG&E employees to continue working at DCPP up until the date of its retirement, but it did not authorize rate recovery for costs of existing agreements made in advance of this decision. PG&E had originally requested $363.4 million for DCPP employee retention and retraining. Second, the $85 million requested for a Community Impacts Mitigation Program was rejected since the decision determined that utility rates should be used to provide utility services rather than government services and that anything done to gain “community goodwill” should be done through shareholder dollars or only done through ratepayers if directed by the Legislature. Third, the $18.6 million in costs previously incurred for its NRC license renewal process and an unspecified amount for cancelled capital projects was approved as reasonable.

CESA supported the PD and the CPUC’s movement toward an all-source solicitation over an energy-efficiency-only procurement approach for replacement resources, while also pushing for consideration of energy storage resources in IRP procurement

See CESA's comments on November 29, 2017 on the Proposed Decision.

On January 16, 2018, Californians for Green Nuclear Power (CGNP) filed an application for rehearing on D.18-01-022 that approved PG&E’s plan to retire the DCPP in 2024 and 2025 when its federal Nuclear Regulatory Commission (NRC) operating licenses expire.  The application for rehearing is premised on the violation of due process rights, the premature change in the use of DCPP given the lack of authorization by the California Coastal Commission, and the lack of certainty that the decision would not increase GHG emissions.

On March 18, 2020, D.20-03-006 was issued that denied the PFM of A4NR because the IRP proceeding should be determining whether the CPUC should create a memorandum account with recorded costs to review the DCPP operation costs through the end of its operating license.

Joint Settlement

On May 23, 2017, PG&E, TURN, ORA, IBEW Local 1245, CUE, NRDC, Environment California, Friends of the Earth, San Luis Obispo Mothers for Peace, and the Alliance for Nuclear Responsibility (A4NR), collectively known as the “Settling Parties”, issued a Joint Motion to approve a settlement regarding the treatment of and cost recovery for license renewal costs and cancelled projects at Diablo Canyon. A telephonic settlement conference was held on May 19 to discuss the proposed settlement terms and conditions and provide an opportunity to comment on the proposed settlement, which includes:

• $18.6 million to recover direct costs related to the April 2011 license renewal

• 25% of the direct costs associated with cancelled capital projects at Diablo Canyon recorded to the project after June 30, 2016

On May 26, 2017, opening briefs were filed by 15 parties on various topics, including timing and cost recovery of the retirement, replacement procurement, and community impacts. Several parties also commented on the lack of evidence to remove the Tranche 2 and 3 replacement procurement proposals as well as the need for all-source solicitations to deliver GHG reductions at the lowest cost. Others focused on how Tranche 1 would not resolve but exacerbate the overgeneration situation, which is expected to be 7,000 GWh of excess energy in 2025.

On August 14, 2017, a letter was submitted to the Commissioners by the Joint Parties (PG&E, NRDC, FOE, CUE, and IBEW) that requested that the CPUC adopt a binding policy decision that the output of Diablo Canyon must be replaced with GHG-free resources in the IRP proceeding, and that the CPUC initiate a procurement program to ensure that all LSEs contract for and build GHG-free resources as replacements to the output of Diablo Canyon.

On December 7, 2018, with the approval of SB 1090, D.18-11-024 was issued that modified D.18-01-022, the decision authorizing the Diablo Canyon Nuclear Power Plant retirement, to approve “full funding” for the community impact mitigation program and the employee retention program. To do so, PG&E was authorized to collect an additional $225.8 million in rates over the amounts authorized in D.18-01-022. The decision did not address the provision in SB 1090 that there should be no increase in GHG emissions resulting from the retirement of this power plant, which was directed to occur in the IRP proceeding, but several parties responded in comments that the CPUC should commit to developing the “appropriate measures” in the IRP. CESA will focus on how Diablo Canyon’s retirement is properly accounted for in the IRP modeling to ensure no GHG emissions increase, which should support potential energy storage procurement.

On October 16, 2019, the A4NR submitted a PFM requesting a modification to the PG&E Diablo Canyon Application Decision (D.18-01-022) to require PG&E to demonstrate that costs incurred to operate Diablo Canyon through the end of its operating license are reasonable and cost-effective in comparison to alternatives, including early retirement. A4NR pointed to the PCIA as the basis for the belated petition. Calls for review of the cost-effectiveness of Diablo Canyon operations was denied in PG&E’s GRC Phase 1 proceeding, which has led to A4NR and others (TURN) to support a PFM here since early retirement is not foreclosed per D.18-01-022. However, the joint settling parties to D.18-01-022 rebutted the PFM by arguing that A4NR has not shown that the IRP could accommodate early retirement of DCPP nor that ratepayer costs would be reduced by early retirement. They also highlighted how SB 1090 “ratified the 2024-2025 retirement timeline, including with the economic package intended to support a well-planned DCPP retirement

2013 Energy Storage (R.10-12-007)

Background

This rulemaking proceeding was opened pursuant to AB 2514 and adopted a collective 1,325 MW procurement target for viable and cost-effective energy storage systems for California’s load serving entities (LSEs). In December 2014, the IOUs issued RFOs for a total of 94.3 MW of energy storage, as required by the CPUC’s D.14-10-05 that approved the utilities’ applications for energy storage procurement authority. No behind-the meter projects were requested by any of the utilities. In December 2015, all three utilities were required to report the results of their energy storage solicitations.

D.13-10-040 established an energy storage procurement goal of 1% of 2020 annual peak load for Community Choice Aggregation (CCA) programs. The Decision also requires that each CCA program file a Tier 2 Advice Letter every two years to show progress toward the 2020 goal, beginning on January 1, 2016.

To count toward the 2020 goal, energy storage projects must meet the following eligibility requirements:

• Energy storage systems must be installed and operational after January 1, 2010.

• Energy storage systems must be online and delivering by December 31, 2024.

• Distributed customer-sited energy storage projects, energy storage from EV programs (e.g., vehicle to grid), and government-funded projects qualify, while energy storage funded by departing utility customers does not qualify.

• Energy storage projects must further a relevant purpose (i.e., grid optimization, renewables integration, and reduce GHG emissions)

• Energy storage procurement must be cost-effective

On August 1, 2018, the IOUs filed a consolidated advice letter indicating that the CCA and ESP energy storage procurement target after applying the automatic limiter have fulfilled their obligations. In other words, with the IOUs recovering many of the costs of their energy storage projects through non-bypassable charges, the CCAs have no remaining procurement obligation when accounting for the CCA and ESP “shares” of those non-bypassable charges. 

On October 24, 2018, the CPUC Energy Division Staff presented a report to stakeholders on the California energy storage market at a workshop on October 24 and provided recommendations on whether additional refinements to the energy storage procurement framework or policies are required. Specifically, staff recommended the following refinements:

• Implement MUA recommendations in a new Storage Rulemaking

• Prioritize Storage Market Evaluation Report

• Refine energy storage procurement requirements

• Consider how BTM Storage can provide grid services

• Refine energy storage interconnection and consider new tariff design

CESA responded to the staff presentation and expressed appreciation to the CPUC and IOUs for the success of the AB 2514 procurement framework to date. In addition, CESA recommended that the CPUC consider our five scoping items for a new Storage Rulemaking:

• MUA implementation and further details (MUA 3.0)

• Emerging energy storage resource pathways, including long-duration energy storage technologies

• Re-contracting existing generation assets to be paired with energy storage

• Standardization of energy storage procurement contracts and approval processes

• Revisit energy storage eligibility

Energy Storage Definition & Eligibility

AB 2514 as reflected in Public Utilities Code 2835 defines an "energy storage system" as commercially available technologies that are capable of absorbing energy, storing it for a period of time, and thereafter dispatching the energy, and may be either centralized or distributed, and may be owned by the LSE, LSE customer, or a third party. Additionally, there is a requirement for energy storage systems to be cost-effective and either reduce GHG emissions, reduce peak electricity demand, defer or substitute for a T&D asset investment, or improve the reliable operation of the electric grid. In terms of technical characteristics, an eligible energy storage system must do one or more of the following:

• Use mechanical, chemical, or thermal processes to store energy that was generated at one time for use at a later time.

• Store thermal energy for direct use for heating or cooling at a later time in a manner that avoids the need to use electricity at that later time.

• Use mechanical, chemical, or thermal processes to store energy generated from renewable resources for use at a later time.

• Use mechanical, chemical, or thermal processes to store energy generated from mechanical processes that would otherwise be wasted for delivery at a later time.

On June 2, 2014, a workshop was held to discuss the CPUC staff proposal on the definition and eligibility of different technologies as "energy storage" under the AB 2514 procurement framework, as well as to review RFO requirements and bid evaluation protocols. The staff proposal reviewed the broad and narrow interpretations of the statute. 

Power Charge Indifference Adjustment (PCIA) Mechanism

On September 15, 2016, a Decision was issued that adopted the Joint IOU Protocol on incorporating energy storage into Power Charge Indifference Adjustment (PCIA) rates. The CPUC stated that the above-market costs associated with energy storage contracts serving the “generation/market function” could be recovered from departing customers via the PCIA. Ultimately, the CPUC rejects the CCA/DA parties’ proposal to include a ‘storage adder’ in the market price benchmark used to calculate above-market costs, but may address this issue in the future. The CPUC acknowledges, for example, that there may be issues related to double counting energy storage costs in calculating the PCIA.

2014 Energy Storage Applications

Background

Every two years, each of the IOUs are required to submit energy storage applications to meet their biennial interim targets as well as to make progress toward their overall 2020 targets. 

PG&E 2014 Energy Storage RFO (A.14-02-007)

PG&E requested offers for 74 MW of energy storage, including 50 MW of transmission and 24 MW of distribution level interconnected energy storage projects. Transmission-interconnected projects must be sized at least 10 MW, and distribution-connected projects must be sized at least 1 MW.

On December 1, 2015, PG&E filed an Application for approval along with Prepared Testimony to the CPUC. In this Application, PG&E sought approval and cost recovery of five energy storage agreements and two purchase and sale agreements resulting from PG&E’s 2014-2015 Energy Storage RFO. One contract was dropped, so PG&E sought approval of the following four energy storage agreements totaling 70 MW for market participation under PG&E's direction, as well as 2 MW for distribution reliability:

• 20 MW transmission-connected contract with Amber Kinetics
  

• 10 MW transmission-connected contract with Hecate Energy
  

• 30 MW transmission-connected contract with Golden Hills Energy Storage (NextEra)
  

• 10 MW distribution-connected contract with Henrietta D Energy Storage (Convergent)
  

• 1 MW distribution-connected contract with Hecate Energy

• 1 MW distribution-connected contract with Hecate Energy

On April 29, 2016, PG&E submitted a Second Application (A.16-04-024) for approval of an agreement with Stem for 4 MW of monthly flexible RA that would count toward its energy storage targets. The project expects expected initial delivery by September 1, 2017 with a duration of 5 years. This Application is a continuation of unfinished negotiations from the 2014 Energy Storage RFO.

On July 20, 2016, the CPUC issued a Proposed Decision approving four energy storage agreements but rejecting two purchase-and-sale agreements (2 MW across two contracts with Hecate Energy). The CPUC determined that the distribution reliability contracts were not cost effective and failed to ensure reliable service in the deferral use case (because the targeted substations would be overloaded before the commercial start date). The focus of CESA's comments were in reaffirming the CPUC in admonishing PG&E for including a term to allow it to terminate contracts if it does not receive desired cost recovery in the CPUC approval process. Such contractual provisions should not be included in future Applications and RFOs.

See CESA's comments on August 9, 2016 on the Proposed Decision.

On September 15, 2016, a Decision (D.16-09-004) was issued that approved the PD that approved the four energy storage agreements (70 MW) for PG&E. 

On October 21, 2016, the CPUC issued a Proposed Decision rejecting a 4-MW energy storage agreement from PG&E's Second Application. This agreement with Stem was rejected because it was not determined to be cost-effective on a Net Market Value (NMV) and Portfolio Adjusted Value (PAV) basis. ORA also commented that the agreement was not competitive compared to other offers outside of the behind-the-meter sector, and not needed to fulfill PG&E’s RA obligations. PG&E and Stem argued for its approval to test an innovative pricing mechanism and add diversity and learning to its portfolio

On December 1, 2016, a Decision (D.16-12-004) was issued that officially rejected a 4-MW energy storage agreement with Stem, which was submitted as a Second Application (A.16-04-024) on April 29, 2016, as a continuation of unfinished negotiations from the 2014 Energy Storage RFO. The CPUC concluded that the agreement does not meet the cost effectiveness test and therefore should be rejected (but can be restructured and re-filed in the next application cycle, if PG&E decides to do so). Given that the CPUC rejected two purchase-and-sale agreements for 2 MW and rejected the Second Application for 4 MW, PG&E did not meet its 2014 procurement target, which is carried over into its 2016 procurement target (falling short by 4 MW).  The 2016 energy storage target should be increased by 4 MW to 119.3 MW.

In February 2017, PG&E terminated the 10-MW transmission-connected contract with Hecate Energy and the 10 MW distribution-connected contract with Convergent because milestones were not met. 

SCE 2014 Energy Storage RFO (A.14-02-009)

SCE requested offers for 16.3 MW of energy storage projects that provide RA only or RA with an option to also be fully dispatchable and provide ancillary services. SCE sought projects that were sized at least 1 MW and interconnected at the transmission or distribution level .

In September 2015, SCE announced selection of the Stanton Energy Reliability Center to contract for 1.3 MW and Western Grid Development to contract for 15 MW of RA capacity, and filed an Application for approval and Prepared Testimony in December 2015.

On July 20, 2016, the CPUC issued a Proposed Decision approving all three RA-only contracts. energy storage agreements but rejecting two purchase-and-sale agreements. The PD also provided guidance on calculating above-market costs for storage, finding that the CCA/DA parties did not sufficiently demonstrate that a storage adder should be included in the Market Price Benchmark at this time, and that the CPUC will re-evaluate the PCIA methodology in 2020.

See CESA's comments on August 9, 2016 on the Proposed Decision.

On September 15, 2016, a Final Decision was issued that approved the PD. 

SDG&E 2014 Distribution Reliability/Power Quality RFP (A.14-02-006)

SDG&E requested offers from suppliers to enter into one or more equipment supply and installation agreements that provide a total of 4 MW of energy storage for distribution and power quality, entailing manufacture, installation and commissioning energy storage systems at locations on SDG&E’s distribution system to be determined by SDG&E.  SDG&E sought the distribution level 4 MW/12 MWh utility-owned energy storage systems in lieu of traditional circuit upgrades. Offers were submitted in March 2015.

On December 1, 2015, SDG&E filed its Post-Solicitation Report, noting that it may have required specifications that were too stringent, resulting in non-cost-effective bids. SDG&E stated its intention to re-launch this RFP to meet its 2016 targets.

Power Charge Indifference Adjustment (PCIA) Mechanism

On September 15, 2016, a Decision was issued that adopted the Joint IOU Protocol on incorporating energy storage into Power Charge Indifference Adjustment (PCIA) rates. The CPUC stated that the above-market costs associated with energy storage contracts serving the “generation/market function” could be recovered from departing customers via the PCIA. Ultimately, the CPUC rejects the CCA/DA parties’ proposal to include a ‘storage adder’ in the market price benchmark used to calculate above-market costs, but may address this issue in the future. The CPUC acknowledges, for example, that there may be issues related to double counting energy storage costs in calculating the PCIA.

2016 Energy Storage Applications

Background

Every two years, each of the IOUs are required to submit energy storage applications to meet their biennial interim targets as well as to make progress toward their overall 2020 targets. 

SCE 2017 Goleta Area RFO

On March 3, 2017, SCE launched the Goleta Area RFO to procure BTM and IFOM DERs to serve the 220/66 kV Goleta substation. SCE seeks to procure electrical energy, capacity, and/or renewable attributes from any of the following DER types:

• Demand response (load reduction or energy storage)

• Standby demand response

• Renewable distributed generation

• Renewable distributed generation paired with energy storage

• Energy storage (RA only or RA with energy put option)

• Permanent load shifting

• Combined heat and power (CHP)

• Fuel cells

SCE is looking to meet a targeted need of up to 55 MW to mitigate potential system issues caused by transmission outages in the Santa Barbara/Goleta area. In particular, there is concern of a rain or fire event that would affect a set of lines, towers, and substations in the area that would lead to rolling blackouts if knocked out. This resiliency need is 14 hours and may be met by a combination of DERs (not all energy storage) that are aggregated by third-party providers by 2018-2020.

On March 22, 2017, SCE held a bidder's conference. SCE set an initial offer deadline for July 10 at 12pm PST and is expected to file an application for CPUC approval of the results on March 30, 2018.

On April 26, 2017, SCE suspended this RFO due to the recent Proposed Decision (PD) rejecting the refurbishment contract for the 54-MW Ellwood gas-fired peaker located within the Goleta A-System (see 2012 LTPP section). The Ellwood contract, if approved by the CPUC, would have enabled SCE to facilitate the effective use of the DERs that SCE is seeking in the Goleta Area RFO in the event of the loss of both Goleta-Santa Clara transmission lines (i.e., an N-2 event). SCE views Ellwood as a bridge to cleaner resources in that it provides the capacity and short circuit duty to allow SCE to accelerate the procurement and deployment of DERs in meeting the resiliency needs in this area until a future portfolio is in place that eventually may not require gas-fired generation. Even though the electrical system in the Santa Barbara/Goleta area meets the NERC reliability standards, SCE believes that Ellwood is a key component of SCE’s Santa Barbara/Goleta resiliency plan in a potential N-2 transmission event, given the area’s unique grid configuration. In an N-2 event without Ellwood or another significant source of short circuit duty, a downed lower voltage power line, even with additional DERs operating on the system, could be undetected for a longer period of time, which poses a significant safety risk. Further, without an energy source like Ellwood, energy storage systems would be inoperable during an N-2 event. Until the final CPUC Decision is issued, SCE will suspend this RFO in order to minimize Offerors’ project development time and costs. In the event SCE resumes this RFO, the RFO would likely restart no earlier than June, and the respective RFO Schedule milestones and, potentially, the DER projects’ start dates would be adjusted accordingly. 

SDG&E 2016 Energy Storage RFO (A.16-03-003)

On March 1, 2016, SDG&E submitted its 2016 Energy Storage Procurement Plan. SDG&E has stated its intention to pursue energy storage to meet its 2016 targets in the following solicitations:

• 2016 Preferred Resources Local Capacity Requirement (LCR) RFO soliciting up to 140 MW from five different product types - including energy storage coming from any of the three grid domains

• 2016 Distribution Reliability/Power Quality RFP soliciting up to 4 MW of utility-owned energy storage systems to potentially enable some measure of distribution capacity deferral, or address reliability and/or provide outage management support

For its 2016 Preferred Resources LCR RFO, SDG&E will use a methodology substantially similar to its Long-Term Procurement Plan (LTPP) methodology. SDG&E expects to have achieved 99.1 MW of energy storage, or 60% of its total target by 2020 (165 MW). But depending on cost, viability and other factors, SDG&E may end up procuring less than what was originally sought by the RFO. CESA expressed disappointment with SDG&E recent energy storage procurement results – i.e., in its 2014 Distribution Reliability RFP and 2014 All-Source LCR RFO. 

See CESA's response on April 11, 2016 on SDG&E's 2016 Energy Storage Procurement Plan.

On April 21, 2016, SDG&E submitted a reply to CESA's response.

On July 29, 2016, a Proposed Decision to approve SDG&E’s framework was issued that rejected its contingency provisions, which “does not serve to reduce project uncertainty, or enable SDG&E to effectively quantify the value of these projects.” CESA reaffirmed the CPUC’s determination in this regard and added that energy storage resources providing RA are already required to operate in accordance with must-offer obligations, which requires that capacity to be made available at system and local peak periods.

See CESA's comments on August 18, 2016 and reply comments on August 23, 2016 on the Proposed Decision.

On September 15, 2016, D.16-09-007 was issued that approved PG&E's framework and found the terms and conditions for the provision of energy storage services to be reasonable. SDG&E was also directed to not include a TOU contingency provision in its selection process. The decision also allowed for the IOUs to maintain flexibility to require interconnection studies but also not to require them to independently forecast potential revenue streams for uncertain or unquantifiable value.  

On December 15, 2017, SDG&E issued its Post-Solicitation Report indicating that it decided not to award a winner in this solicitation yet again. SDG&E decided not to shortlist any of the conforming bidders based on its cost-effectiveness analysis.

SDG&E 2016 Distribution Reliability/Power Quality RFP

SDG&E requested offers from suppliers in 2014 to enter into one or more equipment supply and installation agreements that provide a total of 4 MW of energy storage for distribution and power quality, entailing manufacture, installation and commissioning energy storage systems at locations on SDG&E’s distribution system to be determined by SDG&E.  SDG&E sought the distribution level 4 MW/12 MWh utility-owned energy storage systems in lieu of traditional circuit upgrades. Offers were submitted in March 2015.

On December 1, 2015, SDG&E filed its Post-Solicitation Report, noting that it may have required specifications that were too stringent, resulting in non-cost-effective bids. SDG&E stated its intention to re-launch this RFP to meet its 2016 targets.

On December 1, 2016, SDG&E re-launched this RFP to solicit bids for energy storage systems to address power quality issues on the distribution system and enable some measure of distribution deferral. SDG&E forecasts overload on one 12/69 transformer within SDG&E’s Jamacha substation. Since space inside the existing substation is extremely limited and adding a new transformer bank to resolve the forecasted overloads is not possible absent a costly redesign and expansion of the entire substation, this RFP will assess whether energy storage installed on SDG&E-owned property adjacent to and encompassing the Jamacha substation property might resolve the overload issues at a lower cost than the substation redesign and expansion.

SDG&E is seeking to negotiate and enter into an Engineer, Procure, and Construct (EPC) Agreement for a total of 3 MW (12 MWh) of energy storage, under which the energy storage supplier would install and commission the energy storage on SDG&E-owned property adjacent to and encompassing its Jamacha substation. All documents are available on PowerAdvocate. The RFP closes on March 31 and SDG&E is targeting December 1 to file its Application for CPUC approval.

On March 31, 2017, the RFP closed to bids.

2018 Energy Storage Applications

Background

Every two years, each of the IOUs are required to submit energy storage applications to meet their biennial interim targets as well as to make progress toward their overall 2020 targets. 

On May 24, 2018, a Scoping Memo was issued that consolidated the IOU applications but split the consideration of AB 2514 and AB 2868 policy issues along different parallel paths. On AB 2514 matters, the Scoping Memo aimed to assess whether the procurement plans meet the targets and requirements and adhere to past decisions (e.g., MUA rules from D.18-01-003). CESA’s issues for around technology diversity and reasonableness of deferring procurement to later cycles were included in the scope. No testimonies or briefs have been served on the AB 2514 issues, suggesting that many of these issues are not contentious. Meanwhile, for AB 2868 matters, the Scoping Memo mainly aimed to evaluate compliance with statutory requirements. Specifically, because SDG&E proposed detailed weighting approaches to the statutory criteria, the Scoping Memo included the question on whether this approach is reasonable into the scope.

PG&E 2018 Energy Storage Procurement & Investment Plan (A.18-03-001)

On March 1, 2018, PG&E filed its biennial 2018 Energy Storage Procurement & Investment Plan Application for CPUC approval. This application included its plans for AB 2514 procurement as well as its AB 2868 programs and investments. After deferring some procurement to later biennial cycles, PG&E still has significant progress to make in meeting their AB 2514 procurement targets (160 MW to meet its 2018 interim targets). Overall, PG&E has taken the strategy of deferring AB 2514 procurement due to the lack of any pressing capacity needs (i.e., PG&E has a long position on capacity at the moment, which is also impacted by load departure to CCAs). Many elements and requirements of its 2018 ES RFO remain the same as in its 2014 ES RFO and 2016 ES RFO. PG&E will consider offers that are at least 1 MW in size but no larger than 100 MW. PG&E indicated that it will provide locations and associated operational requirements where energy storage may be an alternative to T&D investments, adding deferral value to bids sited at these locations.

CESA protested PG&E’s AB 2514 energy storage procurements, seeking to ensure that PG&E achieve success of the solicitations by focusing on near-term grid needs rather than having an overly open-ended solicitation (e.g., having a June 2024 online date requirement) and to encourage PG&E to consider hybrid and alternative energy storage technologies.

See CESA's protest on April 6, 2018 on PG&E's 2018 Energy Storage Procurement & Investment Plan Application

On July 11, 2018, opening briefs were filed. Because of the 567.5 MW of energy storage capacity submitted for CPUC approval through Advice Letter 5322-E in a separate solicitation (i.e., the Resolution E-4909 solicitation), PG&E requested that it be allowed to serve an update via a Tier 1 Advice Letter regarding how approval impacts its 2018 RFO targets and procurement strategy. 

On October 31, 2018, D.18-10-036 was issued that approved PG&E’s AB 2514 plans – the only IOU that indicated that it may to conduct an RFO as part of this biennial solicitation. Because of the 567.5 MW of energy storage capacity submitted for CPUC approval through Advice Letter 5322-E in a separate solicitation (i.e., the Resolution E-4909 solicitation), the decision approved PG&E’s request that it be allowed to serve an update via a Tier 1 Advice Letter regarding how approval impacts its 2018 RFO targets and procurement strategy. CESA supported the PD and agreed that the PD properly defers energy storage diversity issues in these applications, but argued that a new rulemaking is needed to more deeply discuss these policy issues. CESA also recommended that the CPUC affirm that PG&E be allowed to conduct a 2018 Energy Storage RFO to meet residual needs (i.e., 57.35 MW needed to meet cumulative customer-domain targets).

See CESA’s comments on October 15, 2018 on the Proposed Decision

On November 16, 2018, PG&E submitted an advice letter that it will be cancelling its 2018 ES RFO since it has met its 2018 procurement targets pursuant to AB 2514 with the approval of Resolution E-4949. PG&E’s remaining procurement targets through 2020 are 0.5 MW in the distribution domain and 34.7 MW in the customer domain. PG&E may meet its remaining targets in its 2020 ES RFO.

SCE 2018 Energy Storage Procurement & Investment Plan (A.18-03-002)

On March 1, 2018, SCE filed its biennial 2018 Energy Storage Procurement & Investment Plan Application for CPUC approval. This application included its plans for AB 2514 procurement as well as its AB 2868 programs and investments. SCE is very far in their progress to AB 2514 procurement targets, with only procurement needs in the T&D domain to meet their total 2014-2020 targets. Due to energy storage procurement expected to occur outside of the AB 2514 framework, such as through the Moorpark/Goleta RFP, SCE did not propose separate AB 2514 procurement in its application to meet its interim 2018 target of 6.5 MW in the T&D domain. SCE also indicated that it will conduct a 20-MW solicitation for the LA Basin in compliance with SB 801 to address Aliso Canyon reliability issues and to contribute to its AB 2514 procurement target.

CESA protested SCE’s proposal and encouraged SCE to consider hybrid and alternative energy storage technologies.

See CESA's protest on April 6, 2018 on SCE's 2018 Energy Storage Procurement & Investment Plan Application

On July 11, 2018, opening briefs were filed. Notably, ORA contended that any SB 801 procurement beyond the residual 6.5 MW for the 2018 cycle should count toward the AB 2868 authorization. However, SCE responded with differences in "procurement" under AB 2514 versus "programs and investments" under AB 2868, and that any SB 801 procurement beyond the 6.5 MW should count toward their 2020 cycle targets, not their AB 2868 authorization. While not directly impacted, PG&E also responded to this issue that the CPUC should not hold more generally that any third-party-owned resources should count toward AB 2868. 

On August 15, 2018, SCE amended its testimony to indicate that the 6.5 MW deficit for its 2018 AB 2514 target no longer exists due to the CPUC approval of the PRP RFO 2 projects in D.18-07-023 - i.e., eligible procurement through 2018 procurement cycle is 423.58 MW, which is 53.58 MW above its 2018 cumulative target.

On October 31, 2018, D.18-10-036 was issued that approved SCE’s proposed plans to have the SB 801 solicitation be the primary energy storage procurement activity for the 2018 biennial cycle. CESA supported the PD and agreed that the PD properly defers energy storage diversity issues in these applications, but argued that a new rulemaking is needed to more deeply discuss these policy issues.

See CESA’s comments on October 15, 2018 on the Proposed Decision

SDG&E 2018 Energy Storage Procurement & Investment Plan (A.18-02-016)

On February 12, 2018, SDG&E launched its Request for Information (RFI) by which it will identify a shortlist by March 30, 2018 to send the RFP for the forthcoming A.18-02-016 investments.

On February 28, 2018, SDG&E filed its biennial 2018 Energy Storage Procurement & Investment Plan Application for CPUC approval. This application includes its plans for AB 2514 procurement as well as its AB 2868 programs and investments. SDG&E is very far in their progress to AB 2514 procurement targets, 6.5 MW left to meet their overall 2014-2020 customer domain target. Given the local capacity needs due to several planned generation retirements and the Aliso Canyon facility partial shutdown, SDG&E has procured energy storage to meet local capacity requirements (LCR) outside of the AB 2514 framework but that still count toward meeting their procurement targets.

SDG&E did not propose further AB 2514 procurement as it is on track to meet its targets. As a result, their application is focused on AB 2868 programs and investments, including seven circuit-level microgrid energy storage projects being proposed. SDG&E is seeking 100 MW in energy storage through these projects, amounting to a $284-million total request. SDG&E identified locations on existing SDG&E-owned property and connected at 12-kV distribution system, with room at site for future expansions to increase energy storage duration. The solicitation process has already begun for its circuit-level microgrid energy storage investments.

On October 31, 2018, D.18-10-036 was issued that approved the AB 2514 plans for SDG&E to not run a solicitation in the 2018 biennial cycle given that it has met its obligations in the transmission and distribution domains. CESA supported the PD on AB 2514 issues and agreed that the PD rightly deferred energy storage diversity issues in these applications, but a new rulemaking is needed to more deeply discuss these policy issues. CESA will also recommended a small correction for the MW count for the AES Fallbrook Project (from 8.85 MW to 40 MW), but was corrected by SDG&E in reply comments.

See CESA’s comments on October 15, 2018 on the Proposed Decision

2020 Energy Storage Applications

Background

Every two years, each of the investor-owned utilities (IOUs) are required to submit energy storage applications to meet their biennial interim targets as well as to make progress toward their overall 2020 targets. 

Each of the IOUs submitted their biennial 2020 Energy Storage Applications pursuant to AB 2514 and AB 2868, with this being the last storage-specific application as required by the CPUC. The 2020 energy storage applications were not surprising for the lack of proposed incremental storage procurement as California entered a "post-mandate" or "post-AB2514" world and instead entered a world where the IRP modeling and planning processes are likely to drive storage procurements. 

A key takeaway from the storage procurement updates has been the significant levels of project attrition due to contract terminations, which point to expected learning processes for storage project development but also to risks faced with permitting timelines, customer acquisition timelines, and/or protracted regulatory approval processes.

PG&E 2020 Energy Storage Procurement & Investment Plan (A.20-03-002)

On March 2, 2020, PG&E submitted its 2020 biennial storage procurement plan application pursuant to AB 2514 and provided notice and documentation that, given procurement to date, it does not have a need to conduct a 2020 solicitation for this biennial cycle. Since AB 2514 progress was last reported in November 2018, PG&E discussed how it has 47 MW of newly installed storage capacity and a modest net decrease of 13 MW due to the cancellation of two contracts totaling 60 MW (Calstor, Kingston). PG&E will monitor the status of energy storage contracts and procure conduct additional solicitations if a future need arises due to contract failure. Overall, after applying the “domain transfer rules” for compliance, PG&E identified a 20.912 MW residual need in the customer domain, which will likely be addressed through SGIP projects within 1-2 years, well before the cumulative compliance deadline of 2024.

The lack of AB 2514 procurement need was not surprising given CESA’s tracking of procurements through 2014-2018, where most of the storage targets were generally met. CESA offered general support for PG&E’s procurement update, where we have little concern that PG&E will meet their 2020 and cumulative targets. Our key recommendation was that the CPUC add energy storage diversity issues in the scope of the 2020 Application, where the CPUC should consider whether incremental procurement targets for technologies with “diverse” and beneficial attributes that will be needed for current and long-term grid needs (e.g., long-duration storage). Questions were posed to consider in the scope of the proceeding.

See CESA’s response on April 3, 2020 on PG&E’s 2020 Energy Storage Application

PAO and GPI protested the application on grounds that PG&E must substantiate compliance with AB 2514 and AB 2868. PAO particularly commented on the need to provide greater detail on SGIP accounting for counting in the customer domain and concerns about how IRP procurement will be counted given modified CAM recovery for approved contracts.

SCE 2020 Energy Storage Procurement & Investment Plan (A.20-03-004)

On March 2, 2020, SCE submitted its 2020 biennial storage procurement plan application pursuant to AB 2514 and provided notice and documentation that, given procurement to date, it does not have a need to conduct a 2020 solicitation for this biennial cycle. SCE highlighted how it has procured 609 MW of eligible storage, exceeding its cumulative targets even after accounting for “domain transfer rules” for compliance. In addition, SCE explained that additional storage may be procured in 2020 from other ongoing or planned solicitations, including:

• 2021-2023 System Reliability RFO

• Reliability Utility Owned Energy Storage (RUOES) RFP

• 2020 Distribution Investment Deferral Framework (DIDF) RFO

• Microgrids Pilot RFP (if approved in R.19-09-009)

The lack of AB 2514 procurement need was not surprising given CESA’s tracking of procurements through 2014-2018, where most of the storage targets were generally met. Notably, a number of energy storage contracts were reported as being terminated, leading to a reduction in the net procurement of BTM resources and Preferred Resource Pilot (PRP) 2 Pilot resources, pointing to the challenges of customer acquisition and the challenges of deploying resources under tight timelines with extensive regulatory approval processes.

CESA offered general support for SCE’s procurement update, where we have little concern that SCE will meet their 2020 and cumulative targets. Our key recommendation was that the CPUC add energy storage diversity issues in the scope of the 2020 Application, where the CPUC should consider whether incremental procurement targets for technologies with “diverse” and beneficial attributes that will be needed for current and long-term grid needs (e.g., long-duration storage). Questions were posed to consider in the scope of the proceeding.

See CESA’s response on April 3, 2020 on SCE’s 2020 Energy Storage Application

PAO, GPI, and TURN protested the application on grounds that SCE must substantiate compliance with AB 2514 and AB 2868. PAO particularly commented on the need to provide greater detail on SGIP accounting for counting in the customer domain and concerns about how IRP procurement will be counted given modified CAM recovery for approved contracts.

SDG&E 2020 Energy Storage Procurement & Investment Plan (A.20-03-003)

CESA generally supported the intent of the programs but reserved full assessment and recommendations upon further review later in this proceeding. Our key recommendation was that the CPUC add energy storage diversity issues in the scope of the 2020 Application, where the CPUC should consider whether incremental procurement targets for technologies with “diverse” and beneficial attributes that will be needed for current and long-term grid needs (e.g., long-duration storage). Questions are posed to consider in the scope of the proceeding.

See CESA’s response on April 3, 2020 on SCE’s 2020 Energy Storage Application

Regarding the BTM incentive pilots, PAO focused on the need to ensure that the programs are sufficiently unique from SGIP, while TURN commented on the need to ensure pilot scalability and data collection and reporting.

AB 2868 Investments & Programs

Background

AB 2868 programs and investments by the IOUs must meet the following statutory criteria:

• Are the distributed energy storage systems connected to the distribution system or located on the customer side of the meter?

• Do the distributed energy storage systems have a useful life of at least 10 years?

• Can the electrical corporation manage the charging and discharging of the system in a way that provides ratepayer benefits?

• Do the program and investments achieve ratepayer benefits, seek to minimize overall costs and maximize overall benefits?

• Do the programs and investments reduce dependence on petroleum, meet air quality standards, and reduce emissions of greenhouse gases?

• Do the proposed programs and investments not unreasonably limit or impair the ability of non-utility enterprises to market and deploy energy storage systems?

• Does the utility in question propose programs and investments of no more than 166.66 MW?

• Do the proposed programs and investments provide for no more than 25% of the capacity of the distributed energy storage systems to be provided by BTM systems?

• Can the proposed programs and investments be prioritized to benefit the public-sector and low-income customers?

• Does the utility's proposed cost recovery mechanism provide that the costs for the programs and investments are recovered in proportion to the benefits received?

On September 14, 2017, the CPUC convened the first of two workshops on the implementation of AB 2868 to align stakeholder views on statutory goals, definitions, and requirements. During this workshop, the IOUs addressed their views on:

• Defining the statutory factors and requirements, which include ratepayer benefits, maximizing overall benefits, minimizing overall costs, reducing petroleum dependence, and reducing GHG emissions

• Acceptable weighting of the statutory factors to evaluate projects

• Defining attributes of energy storage management systems

• Role of energy storage management systems, including utility dispatch of storage systems

• How to determine whether a distributed energy storage system achieves each of the statutory requirements

• Applicability of protocols used to evaluate bids under the existing Storage Procurement Framework

• How to measure reduced petroleum dependence, reduced GHG emissions, and meeting of air quality standards

• Applicability of the Consistent Evaluation Protocol (CEP) and any changes to the CEP to evaluate distributed energy storage resources

The workshop also discussed how AB 2868 is silent on how it applies to CCAs and ESPs and the potential for Distributed Energy Resource Management Systems (DERMs), which are currently being developed by SCE to allow DERs to be controllable for reliability purposes. Certain parties also recommended that a specific percentage of projects or investments be explicitly reserved for low-income customers. Numerous parties filed informal comments on October 2. CESA entered the workshop with some prepared points on key principles and components of a viable and successful AB 2868 application. These included the following:

• CESA prefers the use of programs with standardized offers, pre-qualification of vendors, and agreed-upon program MW cap to facilitate faster contract negotiations and deployments.

• CESA seeks clarification on the various markets served by “distributed systems” including how this applies to IFOM and BTM systems.

• CESA seeks clearer definition of the prioritization on “public sector” and “low income” sectors and how the private industry is underserving these sectors.

• CESA seeks better definition of “fair and open access” to ensure a competitive market, which involves equal access to load/distribution data, customer marketing, and expeditious interconnection.

• CESA seeks clearer definition of the rules for vendor selection and performance, including penalties for non-performance or under-performance.

• CESA recommends developing a standardized formula to determine what parts of an energy storage project can be ratebased.

On September 15, 2017, CESA held an in-person informal meeting with SDG&E to discuss preliminary ideas for SDG&E’s AB 2868 Application. In preliminary recommendations to SDG&E, CESA sought to create alignment between the roles of IOUs versus industry and ways to encourage private investment, ensure competition and innovation, and prioritize market segments and applications where the private sector has not had much success (e.g., low-income communities).

On October 17, 2017, the second workshop was held where CESA presented on principles and recommendations in implementing AB 2868, while various CESA members presented case studies on public-sector and low-income projects. CESA facilitated a discussion on key challenges and lessons learned. Meanwhile, the IOUs shared several ideas to get stakeholder feedback. Example use cases for AB 2868 applications include:

• IFOM energy storage for community resiliency

• Microgrids for increased reliability

• Distribution deferral

• Energy storage for EV fast-charging infrastructure

• IFOM/BTM energy storage for renewables integration

• Enhanced generation assets

• Energy storage for multi-family low-income customers

• BTM solar value enhancement

• Energy storage for military facilities

• Backup generator substitution

• Energy storage make-ready infrastructure (upgrades)

The IOUs also shared their approach to utility ownership, which would be incorporated into their 2018 Energy Storage Procurement Plans to be filed on March 1, 2018, or alternatively, via an advice letter process. The IOUs recommended against adopting a prescriptive MW allocation breakdown for 2018, 2020, and beyond, and instead plan to propose eligible projects in their 2018 Applications and compare the total proposed MWs to the maximum available to each utility under AB 2868. The IOUs can then track approved/installed MWs and propose the balance in their 2020 Applications. CESA recommended that the IOUs should proceed with investments and programs in areas that are not already being served or considered in other proceedings. In this way, CESA explained that the state can grow the market, serve un-served groups, support compliance on AB 2868 and collaboration with the IOUs, and preserve existing successful market segments from disruption. CESA provided a recommended methodology for how to direct and screen any IOU AB 2868 application ideas. This methodology relies on key principles, listed below.

Furthermore, CESA applied our draft evaluation criteria to the list of twelve ideas provided by the IOUs. CESA’s preliminary screen indicated that the IOUs should focus their AB 2868 applications on three immediately obvious opportunity areas targeting underserved customers:

• IFOM energy storage for community resiliency

• BTM energy storage program for backup generation substitution

• Energy storage make-ready incentive program

The IOUs pushed back against CESA’s proposed principles in their informal comments, instead arguing that the only bar for compliance and appropriateness is the statutory requirements of AB 2868. By extension, the IOUs and the Coalition of Utility Employees (CUE) contended that as long as energy storage by non-utility parties will continue to expand and are not closed off to competition in a given sector, a utility project or investment in that sector meets the “non-impairment standard”. Other parties, however, supported CESA in that the IOUs must justify the need for utility ownership, that the proposed “make-ready” model is not analogous for energy storage as it is for EV infrastructure investments, and that third-party investments and management have a greater potential to reduce ratepayer costs compared to utility-owned projects. Next, the IOUs will preview their March 2018 applications in December.

See CESA's informal comments on October 31, 2017 on the second AB 2868 workshop

On December 15, 2017, a third workshop was held, where the IOUs previewed their March 2018 applications. Each of the IOUs proposed a mix of customer incentive programs and utility-owned energy storage investments, with many of the IOUs tilting more toward utility-owned investments in low-income and disadvantaged communities. A high-level overview of their ideas are below:

Utility ownership (UOG) was a major issue as part of these applications. Utility-owned assets and programs were  subject to least-cost dispatch, as adopted and modified in D.15-05-006 and D.15-12-015. The CPUC also applied a reasonable manager standard for the operation of UOG resources, as adopted and defined in D.11-07-039 and D.16-04-006. 

2020 AB 2868 Programs & Investments (A.20-03-004)

On March 2, 2020, each of the IOUs submitted their 2020 biennial storage procurement plan applications pursuant to AB 2514 as well as for AB 2868. Notably, despite the authority to propose up to 166.66 MW of storage programs or investments under AB 2868, PG&E and SDG&E did not propose any programs or investments. Given the experience of the 2018 applications being rejected, the IOUs may not find the AB 2868 applications to be appealing or preferred due to long regulatory approval timelines and presumably because of the lack of interest in pursuing non-IOU-owned projects. Instead, it appears that the IOUs are shifting their "AB 2868 style" projects and investments for approval through their Wildfire Mitigation Plans (WMPs), which face more expedited regulatory approval timelines given the urgency of mitigating wildfire risks.

Pursuant to AB 2868, SCE proposed two BTM programs. First, SCE proposed New Home Energy Storage Pilot (NHESP) – a $5-million program that will incentivize storage adoption, up to a 12.5-MW target (around 2,581 single-family homes), in new residential housing construction subject to Title 24 PV code requirements. Similar to the New Solar Homes Program (NSHP) for the California Solar Initiative (CSI), this pilot would use upfront mid-stream equipment rebates for housing developers and thus not be duplicative of SGIP. Accounting for cost efficiencies (e.g., no customer acquisition, bulk purchasing), two tiers of incentives rates will be provided for: (1) affordable housing projects ($0.765/Wh); and (2) market-rate or mixed-use projects ($0.135/Wh). Upon verified installation, 50% of NHESP incentives would be paid, with the next 50% paid after verification of home visit and battery programming. Incentive rates will stay fixed for the duration of the pilot. SCE would set aside 25% of funds for affordable housing projects. The goal would be to help with solar overgeneration, provide outage management backup benefits, and support batch installations of dispatch-ready fleets. Key program requirements and preferences include:

• Meet 2019 Title 24 Energy Design Rating (EDR) compliance scores and PV requirements through onsite solar installation

• Limit incentives to no more than 600 units per housing developer for market-rate or mixed-use developers

• Enroll in SCE rate with peak differential of 1.69 or more, where applicable and program batteries to provide customer bill minimization and GHG reduction

• Preference for homes that exceed compliance by 10 EDR points or more and/or homes located on candidate circuits for deferral projects

• Meet Rule 21 smart inverter and communication requirements

With program approval by March 1, 2021, SCE proposed to launch the program in Q1 2022 and operate the program through Q3 2023.

Second, SCE proposed Smart Heat Pump Water Heater (HPWH) Program – a $15-million program modeled after PG&E’s WatterSaver Program (adopted in D.19-06-032). SCE will similarly seek to reduce peak load by up to 5 MW by 2027, arguing that this program would close the gap of EE programs not valuing grid interaction and thermal storage capabilities. Two options are proposed to participate in the program:

• Option 1: Upfront incentive for early replacement of aging electric resistance, propane, or gas water heaters with smart HPWHs combined with a pay-for-performance incentive to use water heaters during non-peak hours.

• Option 2: Pay-for-performance incentive to add control and communication equipment to existing electric water heaters to use water heaters during non-peak hours.

To facilitate Option 1, SCE indicated plans to identify water heaters that use gas and/or are nearing the end of their useful lives while prioritizing identification of low-income, public-sector, and DAC customers. All participants would need to enroll in a residential TOU plan. Other funds from SGIP, SB 1477 programs, and EE programs can be co-leveraged. With program approval by March 1, 2021, SCE proposed to begin customer recruitment in Q4 2022 and launch the program in 2023.

CESA generally supported the intent of the programs but reserved full assessment and recommendations upon further review later in this proceeding.

See CESA’s response on April 3, 2020 on SCE’s 2020 Energy Storage Application

Regarding the BTM incentive pilots, PAO focused on the need to ensure that the programs are sufficiently unique from SGIP, while TURN commented on the need to ensure pilot scalability and data collection and reporting.

2018 AB 2868 Programs & Investments (A.18-02-016, A.18-03-001, A.18-03-002)

On March 1, 2018, each of the three IOUs filed its biennial 2018 Energy Storage Procurement & Investment Plan Application for CPUC approval, which included their proposed AB 2868 programs and investments. Consideration of AB 2868 issues were bifurcated from the consideration of AB 2514 issues. 

On February 26, 2019, a PD was issued that granted PG&E’s BTM thermal storage program proposal but denied SCE’s and SDG&E’s BTM energy storage program proposals for being too similar to the existing SGIP program, which has an Equity Budget category for the targeted class of CARE, multi-family affordable housing, and other low-income customers. Meanwhile, each of the IOUs’ IFOM energy storage investment proposals are rejected unless modified due to insufficient justification for pursuing just utility-owned storage investments and insufficient detail provided in PG&E’s and SCE’s proposals. Interestingly, the PD would require the IOU to include the market value of utility-owned land as a cost of the project since unused or surplus property should have otherwise been sold (i.e., fails the “used and useful” test).

Guidelines are proposed in the PD for each of the IOUs when they submit more specific investment proposals or re-submit their proposals with the necessary modifications, where CESA highlights some of the important ones below:

• Each IOU shall procure 166.66 MW of energy storage with no more 25% of the capacity of distributed energy storage systems

• Each IOU shall procure energy storage through RFOs

• Energy storage procurement shall be cost-effective, meet a LCBF criteria, meet MUA rules, consider all forms of resource ownership

• The IOUs shall negotiate signed contracts within one year of the solicitation and shall submit contracts for CPUC approval within one year of the solicitation

• The IOUs shall include details on AB 2868 criteria, cost-effectiveness analysis, etc. in the application for contract approvals

Overall, the PD told each of the IOUs to come back with greater justification for their proposals and to make improvements according to procurement guidelines listed in Appendix A of the PD, including assurances that there will be broader competition for third-party-owned energy storage projects. Unfortunately, this delayed some near-term energy storage procurement opportunities, particularly for utility-owned systems. The IOUs may not proceed with AB 2868 investment proposals given the outcome of this PD, since AB 2868 is merely an authorization and not a mandate. In addition, the CPUC did use “procurement target” language in the procurement guidelines in Appendix A of the PD, whether intended or not. In sum, near-term procurement opportunities for AB 2868 proposals will likely be delayed, but with the directed modifications to their proposals, we may see the nearest-term opportunity for SDG&E’s investment proposals since they are farthest along in providing project sites, costs, and other details.  

CESA agreed with the PD’s determinations around insufficient justification for some of the proposed IFOM investments but we tried to chart a path forward that ensures that the energy storage market grows to serve the intent of AB 2868 for both IFOM investments and through BTM storage programs. Our comments can be summarized as follows:

• The PD should be modified to direct the utilities to submit supplemental information and plans, whereby some current, some modified, and some future proposed projects could be approved through advice letter filings.

• The CPUC should authorize an advice letter process for approval of contracts after the utilities have re-submitted and received CPUC approval for their applications in compliance with Appendix A guidelines.

• Appendix A guidelines for cost-effectiveness should be modified to reflect how procured energy storage projects should be assessed against both quantitative and qualitative factors under the least-cost, best-fit methodology.

• The PD should be modified to approve the BTM programs that address the disadvantaged community goals of AB 2868.

Multiple parties submitted comments in response to the Ruling that fell into the following themes and topics:

• Utility ownership: SCE, SDG&E, and the utility labor union (CUE) underscored the Legislative intent of AB 2868, citing the distinctions in statutory definitions and CPUC decisions for “investment” versus “procurement”. SDG&E also said that third parties are unlikely to be able to provide the instantaneous resiliency operation needed in this use case. SDG&E and CUE both said that opportunities were made available for third parties through solicitations for EPC contracts and that these use cases were targeted because resiliency was a grid problem that is not monetizable by third parties.

• Utility-owned land: PG&E and SCE focused on the PD’s requirement to have surplus utility-owned land to be factored into the cost-effectiveness assessment for utility-owned projects as a cost based on the market value and “used and useful” criteria. PG&E pointed to the security risks of third parties operating on their land and near their infrastructure, while SCE argued that a reasonable amount of space is used and useful because of the need for potential expansion of distribution infrastructure and that this land was already approved in GRCs. No party argued in favor of this requirement in the PD, pointing to how this solution may not have the record development to stand.

• Cost-effectiveness: The consumer advocates (PAO, TURN) generally sought additional guidance or clarifications regarding the cost-effectiveness showing, with PAO favoring the least-cost best-fit methodologies already established under AB 2514. SDG&E cited how AB 2868 language mirrors that of SB 350 to minimize overall costs and maximize benefits, which is the appropriate metric, not the cost-effectiveness standard from AB 2514. SDG&E also attached some early procurement results demonstrating how three projects are already falling below the proposed cost caps.

• Process: PAO recommended against expeditious processes to ensure ratepayer protections and recommended that Appendix A include descriptions of what is necessary for IOUs to show that a competitive RFO is not feasible.

• BTM Programs: PAO argued that PG&E’s BTM Thermal Storage Program is duplicative of its San Joaquin pilot and how BTM programs should also meet the cost-effectiveness standard of Appendix A. Low-income and affordable housing parties (GRID Alternatives, CHPC), however, pointed to several key differences between the proposed programs and SGIP, including around the specialized third-party program administrator, higher incentive rate, unique workforce education and training requirements, and lack of additional performance requirements for SGIP projects. TURN revised its position in response to comments in support of the BTM programs.

• Other issues: A number of parties raised several out-of-scope issues. Clean Coalition and GPI discussed the merits of a feed-in tariff procurement option because of the burden of RFO processes. SBUA sought to have future proposals consider energy storage technology diversity. The CCA and ESP parties reiterated the need for a uniform cost allocation policy.

In response, CESA reiterated our recommendation for a quick turnaround process for SDG&E to provide additional justifications or to submit additional procurement plans for third-party solutions. Specifically, CESA focused our reply comments on the following points:

• Utility-owned energy storage investments may be deemed reasonable pending supplemental information being provided.

• Third-party-owned energy storage systems are capable of supporting distribution needs through contracts, including for resiliency use cases.

• The proposed BTM energy storage programs are different from and complementary to existing programs and should thus be approved.

• Several issues raised by parties are better addressed in a successor Energy Storage proceeding.

See CESA’s comments and reply comments on March 18, 2019  and March 25, 2019 on the Proposed Decision

On May 24, 2019, an Alternate PD by Commissioner Guzman-Aceves was issued that largely upheld the decision to reject all IFOM proposals and PG&E’s BTM Thermal Storage Program but differed from the original PD in authorizing SCE to move forward with its proposed BTM MASH-SOMAH Program. The Alternate PD would authorize up to $10.1 million in spending, subject to a 4-MW program cap and filing an advice letter within 90 days of the decision issuance for final approval of the program. The advice letter will need to detail the operational requirements to ensure GHG emissions and criteria pollutant reduction and address potential bill savings concerns. The Alternate PD justified this approval based on the need to change the Equity Budget given its underutilization in SGIP, which unfortunately cannot be implemented in a timely manner at this time. As a result, the Alternate PD found it reasonable to approve SCE’s proposal as an interim measure to increase penetration of storage in the low-income multi-family dwelling sector.  However, it was unclear why the Alternate PD approved SCE’s BTM proposal but did not do the same for SDG&E’s BTM proposal, which was not approved due to the neutral positions of parties and the lack of details

CESA commended the Alternate PD for approving SCE's MASH-SOMAH Energy Storage Program, which supports near-term deployments for an underserved market and serves as an effective ‘bridge’ solution as the SGIP proceeding considers fixes and modifications to the Equity Budget. For similar reasons, CESA recommended that the APD be modified to conditionally approve SDG&E’s Expanded CARE Pilot Program, with additional detail provided in an Advice Letter filing to address the CPUC’s concerns. While the chances of further consideration of the IFOM energy storage investments are low without a dual-track RFO for third-party solutions, CESA recommended our procedural pathway again, similar to what we said in response to the original PD, to allow SDG&E to provide additional information that would follow the Appendix A guidelines and address the CPUC’s concerns about the gaps in information presented to date. In doing so, CESA aimed to chart a potential path for approval of some of SDG&E’s projects, if cost-effective, compliant with statutory requirements, and plans are in store for third-party solutions and/or competition.

Several parties submitted opening comments. Each of the IOUs made the same pleas from their comments to the original PD around removing some of the precedential language around how utility-owned land should be incorporated into least-cost, best-fit evaluation methodology, which they argued had no record development and would be unreasonable. SDG&E and labor (CUE) reiterated their position that SDG&E's proposed IFOM energy storage investments should be approved given the Legislative intent, including around accelerating energy storage deployment. Meanwhile, PG&E supported the approval of their proposed BTM Thermal Storage but requested some additional time (120 days after the final decision, not 90 days) to file an advice letter for program implementation, given the additional time needed to develop and launch an RFP for a program administrator. SCE, however, appreciated the Alternate PD's approval of its proposed MASH-SOMAH Energy Storage Program, but indicated that they will consider going forward with the approved program, making it possible that SCE will not go through with the program despite Alternate PD approval of it. Finally, PAO opposed the Alternate PD for approving SCE's BTM program as committing legal error and for duplicating efforts in the SGIP program.

See CESA’s comments on June 13, 2019 on the Alternate Proposed Decision

On June 27, 2019, the Alternate PD was withdrawn from the CPUC voting agenda without any discussion. This was unusual as Alternate PDs are usually heard and discussed, even if they are withdrawn from the voting agenda. The rationale for this process has not yet been made clear.

On July 5, 2019, D.19-06-032 was issued with minor revisions to clarify the intent of the decision, including allowing SDG&E to consider its 2018 RFP results along with the results from a new supplemental RFP that conforms to Appendix A. Notably, despite SDG&E already holding an RFP and submitting an independent evaluator’s report on the RFP, the CPUC concluded that the report contained numerous errors and omissions that made it difficult to impossible to interpret and determine the accuracy of the procurement cost information. In addition to the lack of clarity and the non-standardized approach to valuation, the decision discussed how the report only provided contract cost information but did not substantiate ratepayer benefit. In addition, the decision affirmed that BTM programs must be sufficiently distinct from existing programs such as SGIP. As such, the revised PD directed SCE to submit its MASH/SOMAH proposal in response to the SGIP Ruling related to SB 700 implementation.

As a result, the IFOM investment proposals were denied and would not be approved without a supplemental RFO for third-party-owned systems, leading to a potential year-plus delay in approval for the IFOM energy storage resources solicited by SDG&E. It is unclear at this time whether any of the IOUs, including SDG&E, will pursue IFOM investments going forward

2015 Energy Storage (R.15-03-011)

Track 1 Background

On January 28, 2016, the CPUC adopted D.16-01-032 that approved refinements to the energy storage procurement framework in advance of the 2016 biennial energy storage solicitations. Among other things, the decision established transfer rules from the customer domain to the T&D domain (up to a ceiling of 200% of the existing customer domain targets) while still preserving MW ‘floors’ for procurement in each domain.

On technology eligibility, the decision clarified that DC-based storage used as part of a DC microgrid is an eligible energy storage product, but that hydrogen-based power-to-gas options, when injected into the natural gas pipeline system, is not. 

On cost recovery issues, the decision extended the authorization of the Power Charge Indifference Adjustment (PCIA) mechanism for for the 2016 Energy Storage RFOs and deferred resolution of the request to extend the PCIA mechanism beyond 10 years and to change the PCIA mechanism, which will instead be addressed in the Applications for contract approval. 

The CPUC also decided that the energy storage credit associated with SGIP-funded projects installed by Direct Access (DA) customers would be split 50-50 between the IOU and the DA customer's Energy Service Provider (ESP). In addition, self-funded energy storage projects by DA customers are credited 100% to the DA customer's ESP. The CPUC directed the IOUs to make informational filings on December 1 and June 1 each year to provide a "breakout" of such projects.

2015 Energy Storage (R.15-03-011)

Track 2 Background

On January 5, 2016, a Track 2 Scoping Memo was issued. CESA advocated for a revised procurement target of 5 GW of energy storage by 2030! CESA argued that while energy storage is commercially viable and available and is cost effective in certain applications, energy storage resources are not yet part of the ‘mainstream toolkit’ in California and elsewhere. CESA also weighed in on every other topic mentioned in the Scoping Memo:

• Requesting a separate procurement track for large, long-duration storage with a 1,000-1,500 MW procurement goal by 2030

• Denying eligibility for P2G using existing gas pipelines

• Prioritizing cross-jurisdictional use cases of multi-use applications

• Drawing clear distinctions between auxiliary and station loads

• Supporting consideration of community storage as a use case

See CESA's comments on February 5, 2016 and reply comments on February 19 on the Track 2 Scoping Memo.

On May 2-3, 2016, a CPUC-CAISO joint workshop was held on station power and multiple-use applications (MUAs). CESA is actively engaged in the station power and MUAs issues and presented at the CPUC.

See CESA's workshop presentation on May 3, 2016, comments on May 13, 2016, and reply comments on May 20, 2016 on the Joint Workshop. 

On May 9, 2016, a workshop on the PCIA mechanism was also held, which included competing proposals from the IOUs and CCAs. CESA is only monitoring the PCIA issue.

On September 15, 2016, D.16-09-007 was issued that approved each of the IOUs' 2016 Energy Storage Procurement (ESP) Frameworks with slight modifications. The CPUC:

• Directs the IOUs to provide a breakout of SGIP-funded projects by IOU, CCA, and DA customers for future solicitations

• Clarifies information requirements for distribution deferral projects seeking CPUC approval, but does not require a “utility showing” that energy storage meets “resource needs commensurate with or better than the traditional asset it is intended to defer”

• Clarifies that SGIP project 50-50 split counting b/w IOUs and CCAs/ESPs starts for projects online after January 2016

• Defers cost recovery issues to the applications for approval phase

See CESA's comments on August 18, 2016 on the Proposed Decision.

On April 27, 2017, D.17-04-029 was approved that resolved the remaining Track 2 issues except multiple-use applications. While station power rules appear to move in the right direction, the CPUC wants to defer further storage procurement (aside from the already-planned 2016 Storage RFOs and AB 2868 procurements) to the IRP. Pumped hydro consideration is also deemed an "IRP" matter in the PD.

D.17-04-029 does not expand procurement targets because:

• There is little risk of a lack of energy storage procurement in the near future given 2016 RFOs and AB 2868 requirements
  
  

• The IRP will determine optimal resource mix to meet grid needs
  
  

• The targets are only the minimum that must be procured, not the maximum
  
  

• Operational data is just now becoming available, which will inform potential future target revisions
  
  

D.17-04-029 sets a process for implementing an additional 500 MW of IOU programs and investments pursuant to AB 2868:

• Qualifying systems are those with at least 10 years of useful life and located to the distribution system or connected to the customer side of the meter
  
  

• No more than 25% of the capacity may be behind-the-meter (BTM) energy storage systems
  
  

• Applications will be integrated into existing process and schedule for biennial utility procurement plans
  
  

• Each of the IOUs are directed to incorporate 166.66 MW of distributed energy storage system procurement into their 2018 plans due March 1, 2018
  
  

• The IOUs are directed to host a minimum of two workshops to develop consistent definitions, proposals, and plans consistent with statute, to discuss cost allocation and recovery issues, to discuss third-party competition frameworks, and to hold a preview session of 2018 plans
  
  

• A set-aside for disadvantaged communities in implementing AB 2868 will be considered

D.17-04-029 affirms the 1% ESP/CCA energy storage procurement target with a "limiter":

• The obligation is proportionately reduced by the amount that the combined cost recovery obligation exceeds the utility obligation as a percentage of load
  
  

D.17-04-029 declines to establish new eligibility of certain resource types:

• Controlled charging (V1G) does not provide the same level of grid support as bi-directional storage, requires clarification from (R.13-11-007) of the appropriate point of regulation and VGI communication standards, and can be enabled through price signals and tariffs instead of utility procurement
  
  

• Large pumped storage provides significant benefits but it does not fit here since it is more appropriately scoped into the IRP proceeding
  
  

• Power-to-gas (P2G) uses the natural gas pipeline system as a storage component, which is not eligible (see D.14-10-045)

Furthermore, D.17-04-029 directs SCE to convene a working group on community energy storage to identify issues that must be addressed to reduce barriers to the provision of community storage services to local customers via installation of IFOM energy storage. D.17-04-029 also does not direct any new or revised General Order on safety, as Safety & Enforcement Division (SED) can utilize the checklist in their energy storage inspection at utility-owned sites. Finally, D.17-04-029 granted SCE's motion to withdraw its Petition for Modification (PFM) of D.16-01-032 for expedited approval of ES&DD RFO Option 2 contracts given that SCE has closed Option 2 for consideration. 

Station Power

On January 10, 2017, the CPUC issued a Staff Proposal on station power rule revisions, which includes loads related to battery management systems, thermal regulation, vacuums (for flywheels), IT and communications, lighting, ventilation, and safety as retail (station power) loads. For wholesale, the CPUC proposes to include charging energy, resistive losses, pumps (for flow batteries), power conversions systems, and transformers. One particularly favorable outcome is that the Staff Proposal is proposing to allow ‘permitted netting’ during negative generation (charging) of energy storage systems, but not when they are in an idling state. Permitted netting is a positive rule change for in-front of the meter energy storage and ensures equal treatment with traditional generators. In comments, CESA voiced support for the Staff Proposal while suggesting a few areas of improvement.

Most parties were in favor of the Staff Proposal, except the IOUs. CESA therefore responded to their concerns, particularly challenging their arguments that station power rules are ‘incentives’, their misunderstanding of negative generation, and their requests that station power rules for behind-the-meter energy storage should not be addressed until the issue of multiple-use applications is resolved.

See CESA's comments on January 24, 2017 and reply comments on January 31, 2017 on the Staff Proposal.

On February 17, 2017, a Proposed Decision (PD) was issued. CESA submitted comments and reply comments that focused to defend the improved station power rule revisions, particularly from comments by the IOUs. Relatedly, CESA continued to request that the CPUC have idling energy storage with wholesale market commitments qualify under the revised station power rules, while potentially extending permitted netting rules for behind-the-meter energy storage, pending further consideration by the CPUC. Regarding revised procurement targets, CESA commented that the CPUC should continue to build the record on the merits of revised procurement targets, including whether AB 2868 should be added as an incremental part of AB 2514 procurement targets. Regarding AB 2868 implementation, CESA recommended that the applications be expedited to be due by December 31, 2017, and clarified that 'balancing test' language must be added to avoid anti-competitive programs and investments. Finally, for bulk storage issues, CESA recommended that procurement pathways and AB 33 studies should be added to the Track 2 scope.

See CESA's comments on March 16, 2017 and reply comments on March 21, 2017 on the Proposed Decision.

On April 27, 2017, D.17-04-029 adopted rules as modified for treatment of station power in accordance with the Staff Proposal, but defers adoption of station power rules for behind-the-meter systems:

• Rule 1: “All energy that is consumed (and not resold) used for purposes other than for supporting a resale of energy back into wholesale markets is station power and inherently retail, subject to the CPUC’s rules regarding netting of energy consumption.
  
  

• Rule 2: “All energy drawn from the grid to charge energy storage resources for later resale, including energy associated with efficiency losses should be subject to a wholesale tariff.”
  
  

• Rule 3: “Wholesale: charging energy, resistive losses, pumps (for flow batteries and pumped hydro), power conversion system, transformer, battery management system, thermal regulation, and vacuum (for flywheels). Station Power: Information technology and communications, lighting, ventilation, and safety.”
  
  

• Rule 4: Defers approval for sub-metered BTM energy storage resources participating in the wholesale market until further development of protocols, processes, and specific metering configuration options to the MUA discussion later this year

• Rule 5: Station power must be netted against the absolute value of a storage charge/discharge within 15-minute intervals, but permitted netting policy does not apply when storage is idling as storage is unable to self-supply

• Metering: No specific metering configuration is mandated at this time, and the measurement of station power should be left to the seller/LSE, as there is insufficient record at this time on metering costs and some flexibility is needed at this stage of the market
  
  

• Information: The IOUs are directed to include a provision in their station power tariffs to have non-utility schedulers provide information to be able to conduct netting

Multiple-Use Applications (MUAs)

On May 18, 2017, the CPUC Staff Proposal was issued that proposed a multiple-use applications (MUAs) framework according to “(physical) grid domains” and “service domains”. Specifically, the Staff Proposal outlined 20 different services that storage can provide, which map onto five service domains and three grid domains. Furthermore, 16 rules were proposed in the Staff Proposal that governs which and how different services can be provided from the same storage resource. Finally, the Staff Proposal did not resolve but tees up key questions related to double compensation issues for MUAs and metering and other implementation considerations for revised station power rules pursuant to D.17-04-029. The CPUC’s Staff believes that it is useful to designate certain services as crucial to the reliable operation of the electric system (“reliability services”), versus other services that have their prioritization driven by price signals, financial incentives, and penalties (“non-reliability services”). The Staff Proposal has defined a set of rules that prioritize "reliability services" over "non-reliability services", and only allows for one reliability service to be provided. For example, as defined in the Staff Proposal, an energy storage resource cannot provide both frequency regulation and transmission or distribution deferral. If CESA members believe this MUA framework is workable, it will be important to ensure that the categorization of different services as reliability versus non-reliability is correct and appropriate.

On June 2, 2017, a joint CPUC-CAISO workshop on MUAs was held, where the morning session was spent discussing the Staff Proposal and the afternoon session was spent discussing station power and metering integrity needs to ensure accuracy of station power for BTM energy storage involved in MUAs. CESA presented at the morning session to discuss our principles for guiding MUAs:

• Promote participation and efficiency from MUAs while guarding against potential bad actors

• Maintain integrity for wholesale-retail and NEM accounting

• Drive MUA behavior through market signals, operating needs, and economic consequences

CESA also presented at the afternoon session to lead a panel discussion on station power for BTM energy storage configurations, advocating for options such as baselines, estimation, and/or sampling in addition to metering to account for station power. While fewer issues are presented by non-export energy storage systems, there may be more scrutiny needed for exporting energy storage systems. 

See CESA's presentation at the June 2, 2017 workshop on MUAs and station power.

CESA seeks to authorize a broad array of MUAs while also agreeing to key principles for how MUAs should operate based on market signals, contracts, or other tools. For example, MUAs should operate to maintain accurate accounting of retail versus wholesale energy and should not allow for any inappropriate double payments. To accomplish this, CESA proposed an ‘approval checklist’ idea that includes reasonable assurance that an MUA will deliver on promised services, but also suggested changes to the CPUC-CAISO approach, which is less preferable since it is more prescriptive than CESA’s approach. CESA also sought to preserve broad optionality regarding which metering or performance measurement approaches are appropriate while noting that wholesale versus retail actions should be differentiated for billing purposes.

See CESA's comments on June 16, 2017 and reply comments on June 30 on the MUA Staff Proposal.

On November 3, 2017, a PD was issued on November 3 that proposed to adopt twelve rules to govern evaluation of MUAs of energy storage along with definitions of service domains, reliability services, and non-reliability services. Counter to CESA’s views, the PD commented that “most tariffs, contract provisions, and rules assume that a resource will only provide one service” as reasons for why a system of penalties and incentives attached to each service would not work for MUAs, especially to provide two reliability services at the same time using the same capacity. A revised report was attached to the PD that clarified the terms “device”, “resource”, and “capacity” to address confusion for small aggregated storage systems, and adopted three MUA categories – (1) time-differentiated MUAs, (2) capacity-differentiated MUAs, and (3) simultaneous MUAs – where the first type would allow for multiple reliability services to be provided using the same capacity if they occur in different time intervals. Like the Staff Proposal, the PD proposed to adopt a structure of domains and services to follow jurisdictional and physical points of interconnection, with services specific to each domain. However, in contrast to the May 2017 Staff Proposal, the PD changed voltage support, resilience/microgrid/islanding, and system capacity into the reliability services category. This PD represents a few key tweaks to the May 2017 Staff Proposal that first proposed this MUA framework. Importantly, some of the previous rules are consolidated and revised with broader language related to how jurisdiction dictates what the performance requirements and penalties are, especially when providing deferral services. The PD also proposed CESA’s recommended revisions to adopt time dimensions to how multiple reliability services can be provided using the same capacity. Specifically, the framework was organized as time-differentiated MUAs, capacity-differentiated MUAs, and simultaneous MUAs. The PD also clarified how RA resources can deliver their capacity in different ways in accordance with current rules and practices, maintains the rules on reliability services taking priority and maintains rules against inappropriate double compensation. Additionally, the PD left metering configurations for station power treatment to LSEs and energy storage providers. Finally, the PD moved away from identifying specific use cases for MUAs and instead creates a framework that enables the “stacking” of any number of services within the 12 defined rules.

Despite these positive tweaks, there are several areas of concern. For example, Rule 10 requires energy storage providers to submit information in utility solicitations on other services and applications that they plan to provide, which may be used to evaluate and rank bids. This may be problematic due to the ambiguity of “windfall profits” in the rule, as well as how this information is being used to reduce the value of energy storage that is able to provide multiple services, when in fact the energy storage resource should be more highly valued as cost-effective given its greater utilization. CESA also saw some of the rules related to contractual obligations to be duplicative and unnecessary. CESA discussed how the proposed MUA Framework is too limiting and overly restrictive in several ways, causing “value to be left on the table”. CESA instead recommended that several of the proposed rules be changed to avoid barriers and to ensure reasonable development and operation for MUAs, including Rules 6, 8, 10, and 11. CESA added that the CPUC should affirm support for dual participation in programs. Finally, CESA commented on how there are outstanding or eventual matters related to energy storage procurement and policies that need to be addressed, which is a case for keeping this proceeding open. CESA supported comments by SDG&E that a principles-based approach offers more flexibility to broadly authorize MUAs if they meet key principles and checks. CESA’s other points are summarized as follows:

• Rule 10 is unreasonable and flawed and should be stricken entirely based on concerns highlighted by both the energy storage seller and buyer communities.

• The need for energy storage resources to recharge is already considered in Rule 6.

• The application of the MUA framework to technologies and areas outside the scope of this proceeding is not a timely or relevant issue for this proceeding.

• There are sufficient grounds to keep this proceeding open.

See CESA's comments on November 28, 2017 and reply comments on December 4, 2017 on the MUA Proposed Decision.

On January 17, 2018, D.18-01-003 was issued that adopted 11 rules to govern evaluation of multiple-use applications (MUAs) of energy storage along with definitions of service domains, reliability services, and non-reliability services. In sum, the key changes from the original PD include:

• Adopting CESA’s language for Rule 6 that broadened the language to not limit certain workable simultaneous MUAs.

• Deletion of Rule 7 since modifications to Rule 6 cover the applications where energy storage resources can provide both RA and other reliability services, thus making Rule 7 redundant with Rule 6.

• Adopting CESA’s language for Rule 8 to reflect capacity-differentiated concepts for MUAs.

• Modifying Rule 10 to focus the rule on disclosure and transparency, rather than addressing pricing of additional services or revenue of energy storage providers (CESA asked for this to be stricken entirely, but this represents an improvement).

The decision largely maintained the basic framework of the original PD and adopted the following rules for MUAs (the numbers have changed from the original PD due to the deletion of Rule 7):

• Rule 1: Resources interconnected in the customer domain may provide services in any domain.

• Rule 2: Resources interconnected in the distribution domain may provide services in all domains except the customer domain, with the possible exception of community storage.

• Rule 3: Resources interconnected in the transmission domain may provide services in all domains except the customer or distribution domains.

• Rule 4: Resources interconnected in any grid domain may provide RA, transmission, and wholesale market services.

• Rule 5: If one of the services provided by an energy storage device is a reliability service, then that service must have priority.

• Rule 6: Priority means that a single energy storage device may not contract for two or more different reliability service obligations such that the performance of one obligation renders the resource from being able from being unable to perform the other obligation. New agreements for such obligations, including contracts and tariffs, must specify terms to ensure resource availability, which may include, but should not be limited to, financial penalties.

• Rule 7: If using different portions of capacity to perform services, energy storage providers must clearly demonstrate when contracting for services both the total capacity of the resource, with a guarantee that a certain, distinct capacity be dedicated and available to the capacity-differentiated reliability services.

• Rule 8: For each service, the program rules, contract or tariff relevant to the domain in which the service is provided, must specify enforcement of these rules, including any penalties for non-performance.

• Rule 9: In response to a utility RFO, the energy storage provider is required to list any additional services it currently provides outside of the solicitation. In the event that an energy storage resource is enlisted to provide additional services at a later date, the energy storage provider is required to provide an updated list of all services provided by that resource to the entities that receive service from that resource. The intent of this Rule is to provide transparency in the energy storage market.

• Rule 10: For all services, the energy storage resource must comply with availability and performance requirements specified in its contract with the relevant authority.

• Rule 11: In paying for performance of services, compensation and credit may only be permitted for those services which are incremental or distinct. Services provided must be measurable, and the same service only counted and compensated once to avoid double compensation. This is an interim rule, which may be further refined through the working group process.

In general, the CPUC was not yet comfortable with provision of reliability services in real time being reliant on a resource operator’s financial optimization, even though it is open to re-considering it in the future. Rule 6 was proposed as being one of the main subjects of MUA working group discussion.

On February 9, 2018, the first meeting of the MUA Working Group was held to set its context, scope, and schedule. Incrementality and compensation were teed up to be among the first topics to be addressed by this working group because of its effect on other issues, such as metering and enforcement. Importantly, CESA believes that the incrementality definition coming from this working group will have to determine how it should align with incrementality definitions in other proceedings, such as for DR programs (D.14-06-050 Appendix B was surfaced as a legacy rule that might have an impact on certain MUA use cases, where two hours of DR cannot be added to two hours of energy storage to equal an NQC of four hours of RA capacity) and for the IDER pilots (which defines incrementality based on sourcing mechanisms). Given that the work in this MUA Working Group was specific to energy storage resources, it became a topic of discussion on how incrementality is defined in programs such as the Demand Response Auction Mechanism (DRAM), where capacity is procured for not just energy storage but for traditional DR resources as well. Additional issues were proposed around specific disclosures required as part of Rule 9, implications of Rule 7 when a resource is behind just one meter, and one of the goals being to update contract provisions to streamline MUA authorization.

On March 5, 2018, a second MUA working group meeting was held to focus on the measurement, metering, and settlement of BTM energy storage. SCE raised the issue around CAISO settlement often not matching the IOU meter, leading to unaccounted for energy (UFE), and the issue of implementing meter generation output (MGO) for bundled customers versus CCA customers. PG&E presented on a list of open issues for the IOUs to adopt the MGO configuration for retail baselines and performance evaluation around sub-meter data accuracy requirements, reconciliation of primary retail meter and sub-meter, cost recovery, metering enhancements, and billing. The working group also discussed dual participation rules when multiple entities are calling a resource and whether baselines should be revisited for energy storage as DR when measuring incrementality. Finally, the stakeholders in the meeting were unsure on whether there are measurement, metering, and settlement rules around transmission and distribution level services.

On March 13, 2018, a third meeting was held to focus on the measurement, metering, settlement, and station power for IFOM energy storage resources. The meeting began with a presentation from SCE providing an update on its implementation of recently-adopted station power tariffs for energy storage, which includes netting provisions that are being utilized by some online energy storage projects. Specifically, SCE discussed its difficulties in obtaining CAISO dispatch data for energy storage projects with a non-IOU scheduling coordinator, though there should be a standardized means to have resource owners provide this information to the IOUs. Even though netting is a manual process right now, the CPUC clarified that estimation methods would be allowed, supporting CESA’s concerns of installing meters on everything to implement netting provisions. For ancillary services, LS Power noted that netting can be done using after-the-fact bid and award information.

The working group subsequently discussed how it would develop estimation methodologies, which depends on the available size of retail load, IT implementation and maintenance costs, and processing complexity. The CAISO explained that there can be significant UFE for resources providing both retail and wholesale services, as compared to resources that have all services settled with the CAISO where there is no UFE. The CAISO clarified that energy storage devices that provide transmission services do not have specific metering requirements, while the IOUs discussed how it uses interval data to settle distribution services. LS Power and Demand Energy proposed a baselining methodology (i.e., a default calculation for settlement) and noted that additional meters are not needed if there are not additional wires over which energy flows.

Finally, the working group benefited from discussing specific use cases of time-differentiated, capacity-differentiated, and simultaneous MUAs. It was immediately simple and clear that additional metering would not be needed for time-differentiated MUAs. For capacity-differentiated MUAs, there was no consensus, especially with the IOUs stating that it must accurately account for station loads and determine how it will treat deviations from schedule, but LS Power proposed an idea where the CAISO’s state of charge bid parameter could be used to maintain a ‘buffer’ from other services and ensure sufficient capacity to deliver on the wholesale market service without the need to ‘tag’ units to a function. There was even more ambiguity around simultaneous MUAs. Overall though, the working group appeared to conclude that additional metering would not be needed to provide multiple services.

On March 28, 2018, the working group met to discuss resource performance in compliance with Rules 6 through 10 as adopted in D.18-01-003.  A key outcome of these meetings is that it will determine what processes, provisions, and agreements need to be in place to enable MUAs for contracted energy storage resources. One area of consensus was that guaranteeing specific units of capacity explicitly assigned to each reliability service would be unnecessarily restrictive, but SCE presented a potential problematic scenario where a 10-MW resource is contracted 5 MW for Flex RA and 5 MW for distribution deferral. SCE’s concern is that nothing would happen if the CAISO sends an instruction to charge 5 MW for Flex RA and SCE sends an instruction to discharge 5 MW for distribution deferral. CESA sees this as a rare scenario and the CPUC staff agreed that rules should not be designed for such ‘worst cases’.

Furthermore, the group debated whether distribution-connected energy storage resource should be required to get a version of full capacity deliverability status (FCDS) on the distribution system similar to FCDS for RA on the transmission system.  The IOUs believed that this is necessary (e.g., a study on the maximum amount of allowable penetration on each circuit, charge/discharge limits), while others thought that this is unnecessary because a distribution-level FCDS would not ensure full transmission-system access to the resource. By contrast, Stem raised the point that such deliverability studies are unnecessary given the ICA methodology being developed and rolled out.

Finally, the working group discussed resource performance for each MUA type. Everyone generally agreed that seasonal and monthly time-differentiated MUAs do not present issues and no special protocols or additional rules are required. For weekly MUAs, there were contrasting views on whether MUAs are possible, with one side viewing it as viable so long as the distribution service has primacy while the other side expressed concerns that distribution service needs arise from a specific set of circumstances, not from pre-determining a set of days or weeks for that service. It was generally agreed that daily MUAs are harder to manage when the multiple services overlap partially or are sequential, leading to no time to re-charge the energy storage system. For simultaneous MUAs, such as for distribution deferral and RA, the working group discussed the possibility of using outage procedures to deliver on the distribution service that has priority. At this meeting, CESA also presented on how BTM energy storage systems that serve wholesale and retail functions should be able to estimate wholesale and retail charging using baselines or estimation methodologies (rather than meters) that are later audited by the IOUs.

On April 20, 2018, PG&E circulated a first draft on the BTM measurement, metering, and settlement topic for working group stakeholder review and feedback. PG&E summarized how the IOUs believe that the existing arrangements and configurations under the Demand Response Provider Agreement (DRP-A) for the PDR model are workable, though the Meter Generator Output (MGO) baseline (based on submetering energy storage charge/discharge) has not been approved by the CPUC for use in retail DR programs. The draft report also focused on  how the Distributed Energy Resource Provider Aggregation (DERP-A) faces other key barriers to MUAs – e.g., ability to qualify for RA, 24x7 settlement requirement – that must be addressed before metering and settlements are considered for DERP-A systems. Finally, the report summarized how the metering and settlement mechanisms are being addressed in other proceedings – e.g., SATA Initiative, DRP/IDER proceeding. Thus, the report lacked any specific recommendations for metering, measurement, and settlement for BTM storage systems providing MUAs. Rather, much of the resolution of these issues were kicked to other proceedings/initiatives and/or delayed until more urgent participation and policy barriers are addressed first. The report instead focused more on specific use cases that the CPUC and the CAISO should focus on, as a recommendation that comes out of the report.

CESA disagreed with some of the characterizations and approaches, with our focus on making sure that the DERP-A barriers are addressed. CESA disagreed with PG&E’s framing that the lack of a CPUC proceeding on DERPs means the pathway forward is onerous. CESA also sought to have those barriers clearly outlined here and added our thoughts on the specific use cases that should be the focus of this working group and as directives for other proceedings and initiatives. Overall, this report section lacked any specific recommendations for metering, measurement, and settlement for BTM storage systems providing MUAs. Rather, much of the resolution of these issues were kicked to other proceedings/initiatives and/or delayed until more urgent participation and policy barriers are addressed first. The report instead focused more on specific use cases that the CPUC and the CAISO should focus on, as a recommendation that comes out of the report.

On April 20, 2018, the working group kicked off discussions on incrementality that began with an IOU review of the IDER definition of incrementality based on three “tranches” of sourcing mechanisms – i.e., wholly sourced, partially sourced, and un-sourced. Specifically, guidance from D.16-12-036 and Resolution E-4889 defined incremental as those services offered by existing DERs that are above and beyond what is expected under other programs but encouraged each IOU to keep an open mind to incrementality and not default to the assumption that their portfolio procured every cost-effective resource. In the IDER solicitations, partially incremental is defined as only the portion of the offer that provides “material enhancements” to the existing project (e.g., locational, temporal, increased performance certainty). During the discussion, Stem raised the point that dual DR participation rules must be harmonized with the MUA rules and commented on how participation in DR programs should not be defined as a separate customer service but rather akin to TOU bill management. When it comes to SGIP, the IOUs disagreed that SGIP is strictly a technology incentive program and as a program that guides the provision of grid services. Finally, the working group established that incrementality only matters for perfectly simultaneous MUAs, with the IOUs proposing that the baseline be set based on the primary or first service contracted (“first mover principle”) and/or determining incrementality using energy versus capacity elements.

On May 3, 2018, SDG&E presented the first draft report section on measurement, metering and settlement for IFOM energy storage resources that outlined some of the key takeaways:

• Adequate measurement and telemetry of IFOM storage is required for UDC and CAISO operational visibility and for performance verification, so IFOM energy storage providers should submit a settlement quality meter data plan and measurement plan to the UDC and CAISO and authorize the UDC to obtain day-ahead and real-time schedule information from the CAISO.

• Metering and sub-metering arrangements as defined in the CAISO’s ESDER Initiative are sufficient, but settlements can still be an issue when resources participate as wholesale and retail.

• Some IOUs argued that measurement requirements for station power loads shall be negotiated on a case-by-case basis with each UDC, while other IOUs advocated for consistent and standardized measurement procedures and rules.

• Even though the IOUs believe sub-metering is the most precise method for measurement and argue that metering and telemetry costs are coming down, energy storage developers recommend estimation or baseline methods because of the high costs and physical limitations for metering station loads, especially for smaller IFOM systems.

However, SDG&E identified that there may be additional rules needed to address situations where the measured charge and discharge quantities differ from dispatched quantities. For instance, when the resource is dispatched by the CAISO to charge 1 MW but only charges 0.6 MW due to a capacity-differentiated retail service such as providing distribution deferral to the UDC, it is unclear whether the 1 MW of energy should still be considered wholesale power. Some of the IOUs also expressed some gaming concerns of ex post settlement of services due to the potential for making performance claims that are advantageous. Meanwhile, the CAISO raised concerns around how to allocate costs for unaccounted for energy. Stem introduced the “last in, first out” (LIFO) methodology, which is currently being considered at PJM, as a basis for differentiating wholesale versus retail settlement, which is similar to the weighted average cost of generation (WACOG) approach, according to SDG&E. Interestingly, though PG&E and SDG&E noted that IFOM distribution-connected energy storage resources should have charging at retail, SCE noted that IFOM energy storage resources participating in the IDER pilots are structured to charge at wholesale for providing distribution deferral services under an RA contract with a put option. In general, while some in the working group favored a contract-by-contract approach, the working group seemed to be leaning toward creating a standardized approach to separate wholesale versus retail settlements in order to more systematically address discrepancies and clarify settlements when reliability services are being performed simultaneously.

On May 3, 2018, the working group continued discussions on incrementality on the MGO baseline and net energy metering (NEM) resources in wholesale markets. Stem introduced the concept of three different types of incrementality (mandate, procurement, and compensation) and focused on compensation incrementality, which has not been addressed in CPUC policy and includes topics such as the metered generator output (MGO) baseline. The MGO baseline was created to avoid double compensation between retail and wholesale services, by first determining the typical use of the BTM energy storage resource using a 10-in-10 baseline. Stem argued that compensation incrementality should be based on whether or not the market was expecting the action/service (“typical use”), as opposed to a counterfactual approach used for a DR baseline.  However, SDG&E argued that the CEC already includes DR activity and TOU rate impacts in its aggregate forecast, while the CAISO adjusts demand up to an event day for its daily forecasts.

The other major topic of discussion was around the incrementality and wholesale market participation of NEM-paired storage systems. The CAISO clarified that the PDR model does not preclude NEM systems but also does not allow for export since the DR construct is based on offsetting load. The IOUs disagreed that NEM-plus-storage systems should qualify for RA capacity or be offered incremental compensation given that TOU rates are intended to promote economic decisions, but CESA members differentiated between firm responses due to an RA contract versus expected response due to a tariff or rate. Sunrun also cited its DRAM contracts for NEM-paired storage systems as an example of this simultaneous MUA where energy is sold back to the IOU but is still paid the NEM rate. The IOUs added that the first mover principle may be less apt for tariffs and rates for determining compensation and incrementality. Overall, there is still a lack of consensus on the definition of incrementality, which generally fell into two camps:

• An energy storage resource that is providing one service type (energy or capacity) to the benefit of two different needs should be compensated for both since the dispatch calls were separate and both entities got what they needed.

• An energy storage resource should only be paid for one service if simultaneous, since only one “dispatch” occurred.

Overall, CESA’s goal here was to get clear and actionable rules that could be implemented in practice to provide energy storage providers with certainty when it comes to solicitations. By contrast, CESA viewed the IOUs as wanting to keep the rules vague and flexible to allow for them to make case-by-case showings of incrementality.

On May 17, 2018, the MUA working group continued discussions on resource performance, especially for energy storage resources contracted for a capacity-differentiated MUA that may conflict in dispatch. SCE added that the likelihood of this scenario occurring is both highly local and highly dependent on local loads and suggested that distribution reliability services may need to take primacy or allow for investor-owned utility (IOU) control (e.g., curtailment) due to localized threats to the distribution grid. By contrast, curtailment of a resource responding to a CAISO dispatch would be assigned uninstructed imbalance energy (UIE). The working group agreed that reliability requirements could be incorporated in interconnection agreements, which currently do not include this information. For time differentiated MUAs, the CAISO and IOUs explained that current RA constructs or distribution service RFOs do not solicit reliability services on a sub-monthly basis, though the working group discussed how time-differentiated MUAs within a month (e.g., daily, weekly) may be possible in the future.

The IOUs and the CAISO began a discussion on the need to have real-time transfer of information between them, even though CESA stated that this communication is not needed to enable MUAs. With such a low penetration level of energy storage systems, the IOUs recommended that this information transfer, especially around outages, could occur through manual processes for now. One proposed idea was to design a new dispatch outage to the CAISO that restricts an energy storage resource’s availability to the wholesale market in order to deliver on a distribution-level service.

Next, the working group discussed performance monitoring as well as enforcement and penalties if Rule 6 in the adopted MUA Framework is violated.  Currently, enforcement and penalties are enforced through contracts, or in the case of RA, through the CAISO’s ability to derate a resource for those that fail to deliver or underperform on their net qualifying capacity (NQC). The IOUs clarified that there is currently no ability for resources to take outages for distribution services. PG&E recommended the concept of a registration process for MUAs, which would allow the CAISO and different load serving entities (LSEs) to understand the different types of services that are contracted (e.g., RA for a CCA and distribution services to UDC). However, CESA has argued that the upfront assumption should be that the MUAs are allowed and that the CAISO and utility distribution companies (UDCs) must justify when a particular MUA is not allowed. In the draft report section, the key recommendations from the MUA working group is proposed to be the following:

• The UDC should have primacy in dispatch consistent with the interconnection agreements when a resource providing wholesale services is in conflict with distribution needs.

• With the evolution of DERs, the deliverability construct should continue to be examined to determine if and how processes can improve to ensure that multiple reliability services can be provided by DERs; in the meantime, the capacity provided for multiple reliability services from such DERs should be evaluated for its ability to provide the given service in light of the potential conflicts.

• A future RA proceeding should analyze and develop the parameters necessary to allow resources to provide RA as well as other reliability services without overly relying on such resources given their incrementality uncertainty due to the provision of a second reliability service.

• When contracting for resources to meet UDC’s reliability needs, the utility should evaluate the efficacy of resources providing multiple reliability services in meeting their need during the procurement process.

• The CAISO should continue to evaluate its RA Availability Incentive Mechanism (RAAIM) to ensure that it continues to provide appropriate incentive to RA resources to provide their capacity as required, while the utilities should include in their terms and conditions any necessary penalty and/or payment revocations if the resource fails to provide the reliability service.

On June 7, 2018, the working group continued discussions on the incrementality draft report outline. The IOUs held the view that the current Rule 11 principles for determining incrementality combined with the incrementality framework based on sourcing mechanisms as set in D.16-12-036 from the IDER proceeding are sufficient for assessing incrementality for energy storage MUAs. However, CESA and members shared our views that the current definitions are insufficient to provide clarity to solution providers on how to price bids and suggested that incrementality be better defined under two incrementality categories – planning and compensation – that ensure that the full value of services rendered by energy storage MUAs are accounted for in planning assumptions, procurement contracts, and settlement mechanisms. This is a very contentious issue, but CESA still believed that there are areas of consensus that can be reached on the principles of incrementality, though there may be strong disagreement over specific examples and use cases of applying these principles.

During this working group meeting, SDG&E also worked to finalize this draft report section in collaboration with CESA. One key area of difference in this section is related to the IOU’s view that charging and discharging for distribution deferral services should be charged at the retail rate given that the energy is not intended for resale. Generally, SDG&E preferred the use of contracts to determine how to govern settlements. SDG&E also noted that this is not a ratemaking proceeding and this determination may not be appropriate for this working group. The CPUC clarified that the DRP/IDER proceedings have been focused on technology-neutral grid service definitions and DER sourcing mechanisms and thus did not make any determination on whether energy storage charge and discharge for distribution deferral services should be done at wholesale or retail.

CESA, however, expressed our differing views on this matter, instead arguing that it is more appropriate to account for energy to be “settled” as system losses akin to “system losses” for transformers and other traditional distribution equipment when energy storage resources charge and discharge for distribution deferral services. CESA clarified that such treatment of energy from an energy storage resource is more of tracking and accounting practices where energy is settled indirectly as unaccounted for energy (UFE) rather than a direct settlement. SDG&E disagreed with UFE treatment of energy storage because of the active use of the transmission and distribution infrastructure. Alternatively, CESA proposed CAISO wholesale energy settlement, similar to what SCE did for energy storage resources procured in their IDER pilot RFO, though SDG&E cautioned against generalizing this practice across all IOUs as SDG&E only procured for distribution capacity in their IDER pilot RFO. Finally, CESA disputed the retail settlement of such energy storage resources, which are different from end-use customer load and should not be responsible for non-bypassable charges. In addition, CESA is not aware of an existing retail tariff that would be applicable for this use case. The CPUC proposed assessing a time-dependent distribution rate for the use of the distribution system by the energy storage resource to charge and discharge energy.

On July 13, 2018, a full draft final report was circulated, followed by an in-person meeting on July 23, 2018 to discuss the final details of the report. Overall, the draft recommendations appear to be moving in the right direction by allowing for flexibility to allow for the provision of multiple reliability services based on a more granular understanding of time-differentiated and capacity-differentiated MUAs. SCE at least appeared to be open to consider using RA mechanisms (e.g., derating capacity) to avoid “over-reliance” on energy storage MUAs where the provision of one reliability service may impact the efficacy or timing of another reliability service. However, CESA discussed how the difference in viewpoints lies in how to achieve resource performance for reliability services (e.g., contracts, pre-defined primacy, market signals, time differentiation). CESA expressed its ideas that resource performance concerns can be simplified through time differentiation of MUAs (not just at the monthly or weekly level, but possibly even at the sub-hourly level), which removes the possibility of multiple dispatches at the same time, though overly large time blocks may waste the value of MUAs. Primacy concepts can also be established through interconnection rules and agreements. CESA also disagreed with the characterization of energy storage MUAs not communicating with the CAISO and UDC systems, as distribution systems currently do not communicate with the CAISO market or transmission system and because interconnection agreements already enforce sufficient “checks” on DERs. On resource performance, CESA seeks to broaden the perspective on how resource performance should be ensured, rather than a single perspective for primacy and RA rule changes.

As for incrementality, viewpoints diverged significantly from the IOUs and industry participants. Building off the report outline developed by Stem, CESA proposed incrementality categories that, first, ensure that energy storage resources are procured for the incremental value that they can provide “planning and procurement incrementality”, which in the context of IOU planning assumptions may lead to some incrementality assessment on the firmness and certainty of specific operational profiles, or any additional value that can be provided above and beyond what the IOUs "expected" in determining the identified grid need. Second, the report section aimed to ensure compensation and service incrementality for services provided by energy storage MUAs, which provide guidance to whether and how simultaneous MUAs should be compensation and point to how performance evaluation methodologies (e.g., baselines) should be accurately assessing "expected use" to ensure full compensation of services rendered. Given the contentiousness and differences in views on incrementality with the IOUs, this report section was developed separately from the IOUs, who proposed a different framework that focused on how no changes are needed at this time. The IOUs generally viewed the current MUA Framework Rule 11 and definitions and methodologies developed elsewhere (e.g., IDER, DR, ESDER) were sufficient to allow the IOUs to conduct case-by-case review while putting the burden on bidders to make an incrementality demonstration.

In the final opportunity to shape the report, CESA provided some informal comments to convey the following:

• All our bets should not be put on the DRP-A model as the DERP-A model may be better suited for bi-directional use (including exports) with some fixes.

• More flexibility is reasonable for CPUC-jurisdictional metering and measurement for BTM storage.

• IFOM storage for distribution services should have charging energy treated as “losses” or settled at wholesale rates.

• IOUs seek to predefine “primacy” as the means to ensure resource performance but there are other means to achieve that outcome.

On August 9, 2018, the Final MUA Working Group Report was submitted to the CPUC. Next steps based on this report are unclear.

Energy Storage Diversity

On August 8, 2018, a Ruling was issued in the 2018 Energy Storage Applications proceedings seeking comments on whether the IOUs should prioritize technology diversity in their applications. This is an important and challenging topic to address, but CESA believes that there are benefits to diversity. CESA explained how the CPUC should explore further diversity in energy storage solutions in various ways, including directing some solicitations to address needs other than RA (which typically requires four-hour solutions), such as a longer-duration solution. Barriers to diversity, such as “bankability” issues or very tight response times to solicitations, should be mitigated where reasonable. Definitions and measures for diversity could be developed to guide efforts. At the same time, CESA commented that the CPUC should also “do no harm” to market segments that are already developing, especially as we observe diversity among lithium-ion battery suppliers and developers, all of whom have worked hard to develop competitive solutions and to respond to CPUC’s policy direction. CESA added that the remaining procurement authorization under AB 2514 may be too small to support market diversification goals and so an exploration of solutions to this size issue should be explored. Finally, CESA advocated for a successor Energy Storage rulemaking to help the CPUC evaluate “market transformation,” among other issues.

See CESA’s comments submitted on August 28, 2018 on the Ruling

Given the above points, CESA’s major recommendation to the CPUC was to establish a standalone Energy Storage Emerging Technology Procurement Plan (ES-ETPP) that is incremental to existing AB 2514 procurements, with the below parameters for procurement:

Many parties submitted comments, including those advocating for the need for pumped hydro storage, compressed air energy storage, power-to-gas, hydrogen storage, and sodium-sulfur storage. Some of their recommendations included procurement set-asides as well as protocols, definitions, and barriers to be addressed for their specific energy storage technology (e.g., define renewable methane, establish injection protocols for hydrogen, accommodate charge and discharge at disparate locations, immediate COD timelines). Other comments noted the need for and benefit of a larger focus on longer-duration energy storage. Meanwhile, the IOUs and ORA opposed carve-outs, with SCE and SDG&E both claiming that they are “full” on AB 2514 procurements, while others opposed the need to seek diversity for the sake of diversity and pointed to statutory language, including around the cost-effectiveness requirement. Funding from the Electric Program Investment Charge (EPIC) Program was highlighted as being the appropriate mechanism to support the growth of emerging technologies.

CESA responded to parties’ approaches focused on using the remaining AB 2514 procurements should be mapped instead to CESA’s incremental ES-ETPP. CESA added that AB 2514 goals rightly focus on near-term least-cost, best-fit outcomes but should also target broader market transformation to prepare for future grid conditions, emerging technology definitions should be modified to solutions available for five years, and long-duration energy storage seems prudent to further develop the range of energy storage capabilities and technologies. At the same time, CESA re-emphasized our points to “do no harm” for the remaining AB 2514 energy storage procurement obligations. Finally, while not the core topic for the Ruling, CESA also questioned the IOUs’ reported remaining amounts of energy storage procurement obligations pursuant to D.13-10-040 and sought CPUC clarification.

See CESA’s reply comments on September 5, 2018 on the Ruling

Community Energy Storage

In R.10-12-007, the CPUC issued a staff report that defined community energy storage as a distribution energy storage resource that is typically associated with a cluster of customer load (e.g., residential, campus-like complexes, or commercial development). Capacity can be combined to serve the load in aggregate, or may be dispersed through a development, and may serve the following functions:

• Providing storage capacity for excess output from small-scale renewable energy sources

• Providing smoothing and power quality regulation for intermittent resources

• Providing backup power capability during outages

SCE identified four different applications that could be considered for community energy storage:

1. Storage located at a distribution feeder that is interconnected directly to the utility distribution grid, and operated by the utility to provide distribution reliability

2. A series of batteries connected at several locations within the same local area, aggregated together and operated by the utility distribution company for customer bill management and/or services to the local distribution grid

3. Storage interconnected in front of the meter within a community and operated to provide services to local customers

4. Storage interconnected behind the meter on a large campus or military base in which the campus is served via a single meter

On April 27, 2017, D.17-04-029 noted that "participation in the third application is hindered by the lack of program rules, but the current record does not provide a basis to adopt rules at this time...Issues raised by this application are sufficiently complex to warrant discussion in an informal workshop setting." SCE was thus directed to convene a working group to discuss the third use case highlighted above. It is also directed to consider those in disadvantaged and low-income communities. The working group should prepare a summary of the issues, note any consensus that is reached, and transmit the Working Group Report to the CPUC no later than October 15, 2017. The CPUC will then consider whether to take up this issue again in a future rulemaking. 

On July 28, 2017, SCE convened the first working group to focus on identifying issues to reduce technical, policy, and legal/regulatory barriers to community energy storage, especially for customers in disadvantaged and low-income communities, via the installation of IFOM energy storage. A survey was conducted with working group participants, followed by a discussion on applicable configurations and services. Some of the notable barriers include a lack of a Rule 21 interconnection process for IFOM community energy storage and a consensus definition for community energy storage as it relates to size thresholds, locational requirements, and qualification for virtual net energy metering (VNEM).

On September 13, 2017, SCE convened the second working group to focus on identifying issues to reduce barriers to Community Energy Storage, especially customers in disadvantaged and low-income communities, via the installation of IFOM energy storage. The Working Group settled on five potential use cases for community storage:

• Islanding customers in the case of outage

• Customer load-shifting for TOU arbitrage (e.g., VNEM-paired storage)

• Community renewables pairing with energy storage (e.g., Green Tariff Shared Renewables Program)

• Community storage aggregation as Non-Generator Resource (NGR)

• EV and PV load smoothing for grid benefit

SCE is taking the lead on drafting a Working Group report that summarizes the issues and barriers related to community storage and the use cases. The key barriers highlighted include the definition of “community”, consideration of size requirements, FERC jurisdictional issues, utility ownership frameworks, and multiple-use applications.

Calpine Petition for Station Power Regulation (P.16-07-004)

On July 12, 2016, Calpine Corporation submitted a Petition to commence a rulemaking to adopt new rules for netting standards applicable to Station Power Tariffs. At the core, Calpine points to the unfair advantages of 12-month netting periods for NEM generators (reaffirmed in D.16-01-044) as compared to the 15-minute netting periods for larger non-NEM generators, which end up buying larger amounts of retail power from the grid. As a result, Calpine calls for a 12-month netting period to be applied to all California generators, not just for NEM generators. Since this policy issue is not being addressed in any current CPUC proceeding, Calpine requests a rulemaking be commenced.

On November 15, 2016, a Proposed Decision was issued that denied Calpine’s Petition (with support from Independent Energy Producers Association, Shell Energy, and Western Power Trade Forum) to open a rulemaking to revise the IOUs’ station power tariffs with respect to the netting period methodology used in NEM tariffs. The Proposed Decision rejects the Petition on the grounds that there are many and significant differences between NEM customer-generators and merchant generation facilities, including the legislative intent of NEM.

CCA/ESP Automatic Limiter

On November 2, 2017, Draft Resolution E-4892 was issued that directs the IOUs to correct their proposed update to CCA and ESP load data and utility investment and procurement information. This is the context of D.17-04-039, which established an “automatic limiter” designed to ensure that an ESP’s or CCA’s overall contribution to the energy storage target cannot be greater than that of its host IOU, and required that IOUs make annual filings using the most current energy storage procurement and CCA and ESP load data. In recent advice letters, AReM and CCA Parties protested the IOU’s use of outdated CCA and ESP load data, which would have caused the automatic limiter to need to be applied in certain cases, thereby reducing their energy storage procurement obligations. The Draft Resolution basically directs the IOUs to submit supplemental advice letters that correct its compliance filing with the most up-to-date CCA and ESP load data and to directly reflect a reduced CCA and/or ESP procurement obligation if the automatic limiter is hit.

Integrated Resources Planning (R.20-05-003)

Background

On May 14, 2020, an Order Instituting Rulemaking (OIR) was issued to succeed the previous IRP rulemaking (R.16-02-007) that will continue its role as the “umbrella” proceeding for system planning and procurement in line with the GHG goals and reliability requirements through 2030 and 2045. Two tracks will be created:

• Planning track will assess modeling inputs, assumptions, resource valuation, portfolio selection, load forecasting, and analysis of cost, GHG emissions, air pollutants, and reliability. This track will evaluate each of these planning and modeling issues to meet the 2030, 2035, and 2045 goals. Coordination will involve the RPS planning efforts.

• Procurement track will evaluate reliability issues at the system level for renewables and flexible resources, while local reliability needs will be addressed in the RA proceeding (R.17-09-020, R.19-11-009). If procurement needs to be directed out of this proceeding, the CPUC will consider cost allocation policies for on-behalf-of or “backstop” procurement. Procurement of long lead-time (e.g., long duration storage, offshore wind), diverse (e.g., geothermal), and new (e.g., hydrogen-fueled) resources will also be considered.

On June 15, 2020, a Ruling was issued that proposed a three-year cycle for the IRP process, instead of the current structure of conducting each cycle every two years. The three-year cycle proposal was an attempt to balance a number of competing needs that have been identified in the course of conducting the first cycle and part of the second cycle of the current two-year process. The key dilemma was the following:

• Option 1: Continue established process with robust analysis of aggregated LSE plans in the Preferred System Portfolio

• Option 2: Focus the IRP analysis on locational planning, including gas retirements, DCPP replacement, and procurement of long-duration storage and out-of-state wind

CESA supported the general scope and schedule of the proceeding but recommended that the CPUC: extend the IRP planning horizon to 2045 in support of SB 100 goals; revise the mapping guidelines for energy storage resources in order to include social and environmental outcomes; make the retirement or hybridization of natural gas assets a priority of the IRP process; focus on long-duration storage issues in a dedicated sub-track and differentiate their procurement barriers by technology and resource type to meet 2026 and 2030 needs; and issue a procurement Decision before the end of 2020 to address the retirement of Diablo Canyon Power Plant. CESA agreed with the call from parties to prioritize procurement needs and to plan for the retirement of gas generation such that LSEs are guided or directed to conduct orderly, informed, and timely procurement for preferred resources. To this end, CESA respectfully disagreed with the proposed three-year schedule for the IRP as proposed in the Ruling and recommends that the CPUC maintain the current two-year cycle to ensure that modeling is timely and responsive to market conditions and dynamics. The energy storage asset class, for example, represents a constantly evolving and diverse set of technologies that are improving in performance, cost, commercial availability, and configurations (e.g., innovative hybrids) that would face lags in being reflected in modeling exercises under a three-year cycle. Among the two options shared by the CPUC on whether to focus on Preferred System Portfolio analysis and local planning studies, CESA supported the latter. While the CPUC has no authority to force the retirement of gas units, information and guidance is needed to support procurement that drives their retirement.

See CESA’s comments on June 15, 2020 and reply comments on July 6, 2020 on the Ruling

Many parties were generally supportive of the scope and schedule but agreed that more alignment is needed with the RA program to address local needs, prioritization on natural gas retirements, coordination with other agencies to align TPP and long lead-time procurement, and linkages between planning and procurement. Notably, the CAISO agreed with CESA that a procurement decision is needed but with an even more aggressive timeline by Summer 2020 to replace Diablo Canyon capacity and meet resource buildout identified in IRP modeling, expressing concerns with lead times, outdated forecasts, and the lack of procurement to date. By contrast, PG&E, PAO, and AReM argued that more analysis is needed before procurement. To support gas retirements, CalCCA, AWEA, TURN, PAO, CEERT, and the environmental parties (CEJA, Sierra Club, NRDC, UCS) supported a separate track to focus on local reliability issues via procurement guidance (e.g., using CAISO’s local studies), but the CAISO pushed back against simplifying assumptions for gas retirements that can be captured given the current state of IRP modeling. Generally, the CAISO provided a number of modeling-related critiques where the IRP has failed to provide effective mapping of resources including storage, unrealistically designates renewables as energy only, and the RESOLVE capacity expansion model is overly simplified toward least-cost without consideration of diversity or other constraints. Some other parties (SoCalGas, EDF) commented on the need to consider R.20-01-007 for gas-system planning that may impact retirements.

CalCCA, PG&E, SDG&E, and Shell expressed support for a three-year process, which allows for more robust Reference System Portfolio review and aggregation and further modeling of the Preferred System Portfolio. PG&E argued that this would allow for more time to integrate the IRP and local reliability assessments in the RA proceeding. CalCCA preferred to continue with the Preferred System Portfolio development while pursuing a “light version” local analysis in a three-year cycle. SCE preferred to defer on changing the IRP cycle until a more thorough examination of the IRP process is conducted. PCF and solar parties (LSA, SEIA, Vote Solar) supported the three-year cycle but recommended that inputs and assumptions be updated to reflect rapidly-evolving technologies and costs. CAISO and AWEA aligned with CESA on maintaining the two-year process due to the risk of outdated assumptions and the need for faster signals for procurement. Others recommended a hybrid approach to pursue both tracks of work within the two- or three-year cycle.

Separately, the IOUs argued that the No New DER scenario, as implemented, led to over-estimation of the value of DERs since no new DERs are assumed beyond 2019. Least-cost planning would be best served by treating DERs as selectable resources in the RSP rather than using one artificial scenario that forces high-cost resources to be built (i.e., RSP) and a second one that assumes none of them will be built (i.e., no new DER), while calculating avoided costs only based on the second. The Joint Solar Parties, by contrast, rebutted these arguments and added that a new Societal Cost Test (SCT) should be added to the scope.

On September 24, 2020, a Scoping Memo was issued that laid out the scope and schedule of issues to be considered in the new IRP OIR. After contemplating whether the CPUC should prioritize aggregating and processing individual IRPs versus conducting targeted locational analysis, the CPUC opted for a “hybrid approach” that would evaluate the individual IRP filings and aggregate them into a Preferred System Portfolio, but also to consider specific location-oriented analyses at a party’s request, with a priority to consider new resource procurement to replace the procurement of capacity associated with the Diablo Canyon Power Plant (DCPP) retirement in 2024 and 2025. The Scoping Memo reiterated its focus on planning for long lead-time resources, such as long-duration storage. Due to the August 14-15 outages, the CPUC explained that a more comprehensive locational analysis to retire existing gas resources “seems unnecessary and likely ill-advised.” As a result, the scope will continue to be broken out into planning and procurement tracks and will include the following issues:

• General IRP oversight issues, such as individual IRP filing requirements and IRP/RPS filing integration and coordination

• Preferred System Portfolio development and analysis for its reliability, cost, and GHG emissions characteristics

• Resource System Portfolio development, including assumptions and scenarios updates

• Evaluation of the appropriate portfolio for the upcoming 2021-2022 Transmission Planning Process (TPP)

• Procurement of replacement capacity for the 2,280 MW of retiring DCPP capacity

• Evaluation of development needs for long-duration storage, out-of-state wind, offshore wind, geothermal resources, and any other resources with long development lead times

• Local reliability needs, with a preliminary focus on the LA Basin and Greater Fresno areas

• Analysis of the need for specific natural gas plants in local areas, with a particular emphasis on impacts to disadvantaged communities

The Scoping Memo deferred on whether to adopt a two- or three-year IRP cycle and on issues related to backstop procurement and allocations to future IRP decision. The Scoping Memo will DCPP replacement analysis proposed in a Ruling and workshop (January 2021) and culminating in a PD in April 2021. Long lead-time resource procurement issues will be considered via a Ruling in Q2 2021. Finally, a Ruling and PD on the proposed Preferred System Portfolio and associated procurement directives will be prepared through Q3 2021.

Integrated Resources Planning (R.16-02-007)

Background

With the passage of SB 350, the CPUC is gearing toward implementing its requirements, which requires the CPUC to:

• Encourage widespread transportation electrification;

• Double energy efficiency savings from electricity and natural gas end-uses by 2030;

• Increase renewable requirements from 33% by 2020 to 50% by 2030;

• Require resource optimization and an Integrated Resource Planning (IRP) process;

• Support regional expansion of the CAISO; and

• Consider disadvantaged communities in CPUC decision-making processes.

Beginning in 2017, the CPUC is required to adopt a process for each Load Serving Entity (LSE) to file an Integrated Resource Plan (IRP) that balances three major goals: 1) GHG emissions reduction (down 40% from 1990 levels by 2030); 2) system and local reliability; and 3) minimal impact on ratepayers’ bills.

On February 19, 2016 a Rulemaking for the IRP was opened as the successor to R.13-12-010, with many of the issues traditionally associated with the predecessor LTPP proceeding remaining in scope in this proceeding.

On May 26, 2016, a Scoping Memo was issued that set IRP guidance (which includes technical analysis, policy considerations, and administrative rules) as the initial scope of the proceeding, followed by guidance for LSE execution of the IRPs. Topics relevant to CESA members include: future need determinations; guidance on handling long-lead-time resources such as pumped hydroelectric storage and transmission beyond California borders; and coordination with the potential regionalization of CAISO. Importantly, the Low Carbon Grid Study, which CESA cited in support of its higher procurement targets in the Storage Rulemaking, as well as other potential studies, will be used as a starting point in the first round of resource optimization guidance.

On May 14, 2018, an Amended Scoping Memo was issued that maintained the current scope of the proceeding (e.g., production cost modeling in July 2018) but changed the category of the proceeding to “ratesetting” in anticipation of the LSE IRP filings on August 1, 2018 and the subsequent consideration and adoption of the Preferred System Plan in February 2019. It also outlined how the scope of the proceeding going forward will be in refining the RESOLVE model for the 2019-2020 IRP cycle and in enhancing the cross-sectoral analysis to assess whether GHG emissions can be optimally achieved outside of the electricity sector. 

IRP Implementation Options

On August 11, 2016, a CPUC Staff Concept Paper on Integrated Resource Planning was published to serve as a high-level, preliminary concept piece that informs the development of a draft staff proposal on IRP (to be issued in December 2016). It includes a set of guiding principles, essential elements, and underlying terminology for developing and implementing an IRP process at the CPUC. The other topics include the planning framework, division of labor between the CPUC and LSEs, purpose and contents of CPUC guidance in filing IRPs, and other market/regulatory issues.

Overall, CESA generally supported the Staff Concept Paper as a balanced, high-level concept piece but offered several improvements and clarifications to their proposal. In particular, CESA focused on the first guiding principle to be revised to minimize customer costs over a longer term time horizon and to account for all avoided costs and benefits. CESA also added its thoughts on the IRP modeling, filing process, and compliance mechanisms. 

See CESA's informal comments on September 31, 2016 on the CPUC Staff Concept Paper.

On September 26, 2016, the CPUC hosted a workshop on options for implementing the IRP process, as presented in the CPUC Staff Concept Paper and as considered by parties in pre-workshop comments. During the workshop, the CPUC revealed its revisions to the Staff Concept Paper, such as the first guiding principle to ensure reliability and the fifth guiding principle to convey the need to align and/or consolidate resource-planning proceedings with the IRP. Unfortunately, the CPUC rejected recommendations to utilize a longer resource planning horizon because it is “too issue-specific.” The interaction between IRP and resource acquisition will be addressed at a future workshop.

Disadvantaged Communities in the IRP

The CEC issued a Final Report in December 2016, pursuant to SB 350, on overcoming barriers to energy efficiency and renewables for low-income customers and small businesses in disadvantaged communities. Given this backdrop, the CPUC requested comment on how disadvantaged communities, demand-side energy management, and resource-specific proceedings should be incorporated in the IRP, pursuant to SB 350 requirements. 

On February 17, 2017, multiple parties filed comments in response to a Ruling seeking comments on how the IRP should incorporate disadvantaged communities in its consideration of IRPs and resource planning/procurement. CESA focused its comments on ensuring that the definition of "disadvantaged communities" should include low-income communities, and recommending that disadvantaged communities requirements should be incorporated in the IRP through procurement guidance and requirements. Questions related to other miscellaneous SB 350 requirements were also posed. For these, CESA commented that other resource policies and programs, such as AB 2868, should be linked to the IRP to ensure accurate modeling and incremental resource procurements in disadvantaged communities. CESA also added that locational benefits should be considered in the procurement guidelines and evaluation criteria for resources, and that there should be feedback loops between resource-specific proceedings and the IRP proceeding.

See CESA's comments on February 17, 2017 on the SB 350 Miscellaneous Requirements Ruling.

Production Cost Modeling (PCM) Requirements

The objective of production cost modeling (PCM) is to evaluate Reference and Preferred System portfolios with higher operational detail and wider distribution conditions. In addition to reporting reliability level, emissions, renewable generation, curtailment, and production cost on a more probabilistic level, the PCM is intended to verify satisfaction with the Planning Reserve Margin (PRM) requirement and the calculation of marginal Effective Load Carrying Capability (ELCC) values for utility-scale solar and wind. The CPUC's adopted reliability standard is a minimum 15% PRM - i.e., falling short of the PRM will be the basis for determining whether any system reliability-driven additional procurement is necessary. The ELCC values, meanwhile, are used as a component of reserve margin calculations. Reserve margin is the extent to which effective capacity exceeds expected peak demand (i.e., typically a ratio of NQC to average annual peak). For the purposes of PCM, the loss-of-load event occurs when regulation up/down (1.5% of hourly forecast load) or spinning reserves (3.0% of hourly forecast load) cannot be maintained. 

On October 2, 2014, Resolution E-4677 further required that the project results be demonstrated using the assumptions and at least one of the scenarios adopted in the CPUC’s 2016 LTPP proceeding.

On March 25, 2015, a Ruling was issued that concluded that "there is not sufficient evidence at this time to authorize additional flexible or system capacity through 2024" and "there is both sufficient time and a critical need to further develop modeling efforts to inform the 2016 LTPP proceeding regarding the need for flexible capacity through 2026." The Ruling recommended that the proceeding continue to focus on developing and validating models that can “accurately highlight and distinguish needs for both flexible and generic system resource attributes to maintain reliability, to investigate efficient solutions to potential operational flexibility events (such as over-generation events), and to set the stage for expanded future analyses which will balance the  cost-effectiveness and GHG impacts of measures to ensure system reliability.” The Ruling further directed Commission staff to: develop common definitions, metrics, and standards; identify standard outputs; and validate stochastic and deterministic models and make technical improvements.

On September 23, 2016, an ALJ’s Ruling was issued that provided direction and standards for modeling of system and flexibility needs utilizing PCM. The CPUC proposes to use the Strategic Energy Risk Valuation Model (SERVM), which is also used in the RA proceeding. 

On September 19, 2017, a Ruling was issued that laid out the PCM process as it fits within the broader IRP process as well as the proposed calculation for verifying whether the Reference System Plan meets the PRM. Peak demand will be calculated using the IEPR 1-in-2 annual peak consumption forecast adjusted for load-modifying impacts but excluding PTM PV impact. Existing non-wind and non-solar will use the current NQC values while existing and new wind and solar (including BTM PV) will have their average portfolio ELCC values calculated and then discounted by the value of the ratio of fully-deliverable capacity to total capacity. 

The staff proposes to use PCM for the following purposes:

• Benchmark the RESOLVE model results

• Evaluate the operational performance and verify satisfaction of the PRM requirement for the Reference System Plan and a few alternative cases

• Re-evaluate the performance of the Reference System Plan and other alternative cases after incorporation of the 2017 IEPR demand forecast and other data input updates

• Determine the marginal ELCCs of new wind and solar resources

For the 2017 IRP, the CPUC will use the marginal ELCCs derived from the RESOLVE model since the PCM will not be completed by Q1 2018 for the LSEs to begin development of their IRPs. The modeling scope will be limited to the 2022 and 2030 study years given limited staff resources and time.

CES-21 Flexibility Metrics & Standards Project
In 2012, D.12-12-031 and D.14-03-029 authorized the California Energy Systems for the 21st Century (CES-21) “flexibility metrics and standards project” collaborative research partnership between PG&E, SCE, SDG&E, and Lawrence Livermore National Laboratory (LLNL). This project uses the Strategic Energy Risk Valuation Model (SERVM) to assess the reliability and operational flexibility of California’s electric system.  The SERVM model is the same model as used in the RA proceeding to calculating Effective Load Carrying Capability (ELCC). This study aimed to determine whether there is enough flexible capacity to meet grid reliability needs and whether planning standards need to be updated. The key questions for the project included:

• Did the range of projected CAISO system scenarios have sufficient capacity and operating flexibility to meet the 1-in-10 reliability standard in 2026?

• How did operating flexibility, or lack of it, impact costs and emissions (i.e., system operations)? What are the main drivers?

• Do we need to create new planning standards to maintain operational flexibility, and if so, what would those standards be?

The analytical framework and study cases modeled in the CES-21 project are highlighted below:

The CES-21 project explicitly examined contributions from energy storage resources to reliability, economic benefit, and curtailment benefit. The project tested three cases by adding 3,000 MW, 6,000 MW, and 10,000 MW of four-hour duration battery storage to the reference study case and measured the average capacity value for the entire class of four-hour battery storage. For the economic and curtailment benefit runs, the project created four cases, each adding 1,000 MW of a different type of storage device (2, 4, 6, and 8-hour storage) to the reference case. As context, the reference case includes the 1,325 MW of energy storage pursuant to AB 2514 requirements. 

On August 15, 2017, a workshop was held to present the final report of the CES-21) research and development program from the Grid Integration Flexibility Metrics and Standards project.  The CES-21 team presented its directional results based on the 2016 LTPP assumptions and scenarios and using LOLE metrics for generic peak capacity, multi-hour ramping, and intra-hour ramping deficiencies, as well as their associated curtailment, emissions, production costs, and total costs:

• The average ELCC of solar and energy efficiency decreases with higher RPS levels, but those for wind increase slightly and energy storage increase significantly.

• The ELCC values of energy storage are reduced as more storage is added to the system - i.e., due to flattening of the peak net load.

• The marginal curtailment benefit of one MW of Pmin is greatest to a highly inflexible system.

• For the projected 50% RPS system, the marginal economic and curtailment benefits of additional energy decline past a few hours of energy storage.

ELCCs are calculated relative to a generic fossil resource. For each resource type evaluated, the entire portfolio of this specific resource type is removed from the system and generic fossil resources are added to the system until the LOLE of 1 day in 10 years is regained. The amount of generic capacity added is then divided by the nameplate of all the specific resource type removed. Importantly, a key observation was that the average ELCC of solar resources did not decline as rapidly as expected between 43% RPS and 50% RPS, as the jump from 33% RPS to 40% RPS was heavily weighted toward BTM rooftop solar, which generally is sub-optimally oriented and thus provide limited output in late afternoon hours, whereas the jump from the 43% RPS to 50% RPS was heavily weighted toward fixed and tracking utility-scale PV, which are more optimized and show higher output during these hours. In the PRM base case, the 50% RPS portfolio identified a deficiency of 393 MW of generic resource capacity and a PRM of 116.8% to satisfy the LOLE standard. 

When considering intra-hour flexibility, the CES-21 team observed that increasing load following reserve requirements generally reduced intra-hour LOLE events, which occurred mostly during low-load, high-renewable seasons where less resources are committed to serve load yet a large amount of intra-hour volatility existed due to large output from variable generators. However, carrying such high load following reserves came at high cost, the CES-21 team observed. When considering multi-hour flexibility, the CES-21 team observed that there is sufficient flexibility in the system to handle even high Pmin scenarios, but it would sharply increase curtailments. Net exports, in particular, was demonstrated to be an important flexibility solution, and when those capabilities are increased, was demonstrated to have significant impact on reducing curtailments. 

The additional energy storage sensitivity cases showed that the ELCC of four-hour battery storage is not affected the capacity value when 3,000 MW of additional battery storage is added, but that it begins to drop with additions thereafter due to energy storage already doing a lot to flatten the peak net load such that the marginal battery storage device can only cover a portion of the peak. 

Another important insight from the CES-21 project is that the cumulative absolute value of five-minute ramps in a given day increase as we move toward a higher RPS. While absolute ramping does not impact operations, it does show how much overall additional ramping is required. 

Finally, the CES-21 study found that there is a limit to the CAISO's ability to export. During the hours when the CAISO system is experiencing extreme over-supply conditions, the study found that these hours at least partially coincide with similar situations in neighboring areas, thereby implying that there may be an export limit from CAISO resources.

GHG Accounting Methodology

The Legislature adopted AB 1110, which directed the CEC, in consultation with the ARB, to adopt a methodology for the calculation of GHG emissions intensity for both the “purchase of electricity by a retail supplier to serve its retail customers” and “statewide retail electricity sales.”  The CEC issued a proposal in its rulemaking that sought to be consistent with ARB’s GHG emissions and compliance programs by primarily relying on data that is reported through ARB’s Mandatory GHG Reporting Regulation. Stakeholders in the CEC proceeding filed comments in response the CEC’s initial proposal. This proceeding is relevant to the IRP proceeding because PG&E’s Clean Net Short (CNS) Proposal was introduced in the CEC proceeding and adopted in the IRP decision.

On March 1, 2018, the CPUC issued a paper that proposed a GHG accounting methodology that aligns with production cost modeling that staff plans to conduct in 2018 so that individual IRPs may be compared across LSEs and with the Reference System Plan adopted for the 2017-2018 IRP cycle. Specifically, CPUC staff recommended the use of PG&E’s proposed CNS methodology that apportions GHG emissions to each LSE based on its projected hourly electricity demand, including how the LSE plans to rely on CAISO system power on an hourly basis in 2030, which can be done through RESOLVE modeling. The CNS methodology follows the steps below:

• The LSE will subtract out any owned or contracted non-dispatchable GHG-emitting resources it plans to use to serve its hourly load from its projected hourly electricity demand in 2030.

• The LSE will subtract its owned or contracted GHG-free generation (i.e., RPS Bucket 1, hydroelectric, and nuclear) from the projected hourly electricity demand, less the amount in Step 1.

• The LSE will subtract the discharging pattern and add the charging pattern of any storage resources owned by or contracted to the LSE from the hourly profile derived from Step 2.

• The CNS in each hour from Steps 1-3 will be multiplied by the system GHG emissions intensity on an hourly basis yielding total emissions associated with using unspecified system power for that LSE for every hour of 2030.

• The emissions from all owned or contracted non-dispatchable GHG-emitting resources used to serve hourly load in Step 1 will be computed using plant-specific emissions factors and added to the emissions from unspecified system power calculated in Step 4.

Under the CNS method, IOUs would not be solely responsible for emissions from dispatchable resources that they procured on behalf of the system that are subject to the Cost Allocation Mechanism (CAM). Only the emissions from non-dispatchable resources that are not subject to the CAM would remain exclusively with the IOU. Since many energy storage projects are procured via CAM, energy storage charge and discharge may be used in the calculation of the CNS.

On April 3, 2018, a Ruling was issued that included the CPUC proposal for comparing GHG emissions from electricity resource portfolios submitted as part of each LSE’s IRP filings. The purpose of this methodology is distinct from the purposes of either the ARB in accounting for GHG emissions for its GHG emissions compliance programs or the CEC in accounting for GHG emissions as part of the Power Source Disclosure Program – both of which are look-backs for reporting (CEC) and compliance (ARB). The CPUC noted that it is aiming to create a best-available that aligns with the production cost modeling that CPUC staff will conduct in 2018 and allows a comparison across multiple LSEs on a consistent basis. The CPUC staff attached a paper that recommended the use of PG&E’s proposed CNS methodology that apportions GHG emissions to each LSE based on its projected hourly electricity demand, including how the LSE plans to rely on CAISO system power on an hourly basis in 2030, which can be done through RESOLVE modeling. Under the CNS method, IOUs would not be solely responsible for emissions from dispatchable resources that they procured on behalf of the system that are subject to the Cost Allocation Mechanism (CAM). Only the emissions from non-dispatchable resources that are not subject to the CAM would remain exclusively with the IOU. Since many energy storage projects are procured via CAM, energy storage charge and discharge may be used in the calculation of the CNS. The CNS methodology follows the steps below.

CESA supported the proposed CNS method, which should incentivize LSEs to consider energy storage solutions to better ensure GHG emission reductions. While supportive of the proposal, CESA offered suggestions for refinements to the methodology to consider the operational characteristics of energy storage resources operating within the hour and the allocation of GHG credits for resources under shared cost recovery mechanisms, among other things. Multiple parties raised comments with many in support of the CNS methodology (Calpine, CalWEA, NRDC, GPI, CEERT, Clean Coalition, Joint IOUs, and TURN). Others offered recommendations on how to treat certain resources, such as Clean Coalition (wholesale distributed generation resources) and Powerex (out-of-state hydro), or on how to improve the methodology, such as the IOUs, CEJA, and Sierra Club (consider Pmin and startup emissions), TURN (avoid shuffling across WECC), and Calpine (provide some credit for avoided GHG-emitting purchases from excess GHG-free electricity). The non-IOU LSEs were noticeably opposed to the CNS methodology as the CCAs and CMUA raised the point about how the IRP methodology is inconsistent with RPS compliance rules and with accounting methodologies from the CEC and ARB. The CCAs proposed a procurement-based accounting approach instead, and as a backup, recommended that the CNS methodology, if adopted, be based on annual accounting. AReM, representing ESPs, commented that the methodology is limited for ESPs that have load shapes heavily dependent on its customer class and recommended that the GHG Calculator Tool allow for customized load shapes to be entered. ORA was also notable for being relatively neutral by highlighting the need for further analysis and benchmarking and focused on needing to understand the GHG impacts of energy storage dispatch.

See CESA's comments on April 20, 2018 on the Ruling.

In reply comments, SCE raised the issue of vetting CCA load forecasts and commented on the difficulties of long-term planning as CCAs change their forecasts or abandon their implementation plans altogether. A large number of parties also came out against Powerex’s recommendation to include out-of-state hydro resources in the GHG accounting methodology due to concerns about incrementalism and resource shuffling. Additionally, the IOUs as well as a number of other parties opposed CalCCA’s recommendation to adopt an annual accounting approach to the CNS methodology, while CalCCA raised concerns about the incompatibility of the CNS methodology with RESOLVE, which focuses on optimal portfolios on a system-wide basis, highlights the benefits of a solar-heavy RPS, and counts banked renewable energy credits (RECs) toward GHG emission reductions.

On May 25, 2018, a Ruling was issued that adopted the CNS methodology for accounting for GHG emissions of individual LSE portfolios to appropriately account for the GHG content of generation used to meet load in each hour, rather than using a net annual calculation. A key modification in the adopted CNS methodology was that excess GHG-free energy provided to the grid in excess of its load in any given hour will still be credited to the LSE when the GHG-free energy is sold into the system and displaces energy from GHG-emitting resources. The CPUC justified this change to avoid penalizing the procurement of resources that offset GHG-emitting generation, even when these resources generate in excess of the specific LSE’s load. Other key changes in the methodology include:

• Include RPS Bucket 0 resources that were purchased prior to 2010 (i.e., the PCC 1 cutoff date) as GHG-free resources

• Allow for LSEs to input custom load shapes and custom production shapes for GHG-free resources that may be different from default profiles in RESOLVE

• Add heat maps for the dispatch profile of pumped hydro storage resources

In the future, the Ruling discussed how it will incorporate criteria pollutant emissions, apportion GHG benefits of resources procured through non-bypassable charges, account for GHG emissions associated with the Pmin of generation resources, and guard against resource shuffling. Importantly, in response to ORA’s comments, the Ruling highlighted how the CPUC should examine the GHG impacts of standalone storage and hybrid storage solutions. At a high level, the CPUC determined that the GHG accounting methodology is intended for planning (not compliance) purposes so that the CPUC can compare and aggregate the GHG emissions expectations associated with individual LSE plans and allow benchmarking against the Reference System Plan. To address concerns about inconsistencies of GHG accounting for planning and compliance purposes, the Ruling explained that the RPS program has other objectives than GHG emissions reduction, similar to how RPS and cap-and-trade program rules are not entirely consistent, and determined that the IRP is intended to link the RPS program to the state’s GHG emissions reduction goals through planning and targeted procurement.

Confidentiality Treatment of LSE Plans

Many LSEs filed motions to file their LSE Plans under seal to maintain confidentiality, especially around RA and RPS-related information, citing competitiveness reasons, while the IOUs pushed to have CCA motions denied to reveal potential open and short positions on contracted RA volumes. CEJA and Sierra Club pushed strongly back against these motions because they argue that LSEs must “prove” the legal and factual basis for redacting and sealing IRP-related details and information and that the CPUC has narrowly defined “market-sensitive” information that is potentially confidential. In particular, these environmental groups are seeking the ability to evaluate LSE compliance with GHG and air quality requirements.

On October 5, 2018, a Ruling was issued that granted the motions to file under seal of 29 LSEs, who all made slightly different types of requests to file certain categories of information as confidential. The Commissioner and ALJ agreed that there is some risk of anti-competitive behavior by generators in the market if detailed information about either RPS net short or RA net short positions is made public, especially for CCAs and ESPs that compete with IOUs directly for customers. The Ruling erred on the side of confidentiality for LSE-specific information but found that the desired information about RPS/RA positions and GHG emissions could be made public with aggregation. The Ruling acknowledged LSEs are different, with IOUs being both buyers and sellers of energy, leading to it being appropriate to differentiate confidentiality treatment by LSE types.

On November 16, 2018, several parties submitting comments in response to questions posed in the Ruling. The LSEs generally pointed to the definitions of “market-sensitive information” and “market participant” from D.06-06-066 and D.07-05-032 as governing confidentiality and did not recommend changes to it, though the IOUs and CCAs seemed open to allowing non-market participants to access this information subject to an NDA. The IOUs and CCAs agreed that the confidentiality provisions for ESPs should be extended to CCAs but the CCAs and ESPs disagreed with the IOUs that RA contracts and RA short positions should be confidential since IOUs and other LSEs are also competing sellers of RA capacity. TURN and environmental parties, however, called for a comprehensive re-evaluation of the confidentiality framework through a dedicated process to establish uniform guidance because the rules were established in response to the 2000 energy crisis. TURN added that the three-year confidentiality window should be eliminated or shortened given shorter construction timelines of new energy technologies, while Sierra Club and CEJA recommended a disclosure requirement for all IRP data from LSEs beyond three years since this information is long-term planning rather than market-sensitive competitive data. Finally, the PAO and the environmental parties commented that GHG emissions data should never be redacted. Reply comments are due no later than November 30.

Like other non-LSE parties, CESA has been frustrated with the redactions across different LSE plans, which has made it difficult to compare LSE Plans and ensure some degree of compliance with the adopted Reference System Plan and the forthcoming Preferred System Plan, including around planned energy storage procurement. At minimum, CESA will support efforts to ensure consistent and reasonable data redaction standards

Public Utility Regulatory Policies Act (PURPA) (R.18-07-017)

Background

The CPUC has a history of Public Utility Regulatory Policies Act (PURPA) implementation spanning four decades, resulting in more than 4,000 MW of Qualifying Facility (QF) power in operation. Under PURPA, an independently-owned generation facility that meets certain federal eligibility requirements based on size, technology and/or efficiency requirements is entitled to sell its power to regulated utilities at those utilities’ avoided cost – i.e., “must take” obligation. PURPA provides that a utility may not be required to pay a rate to a QF that exceeds the incremental (or avoided) cost to the electric utility of alternative electric energy. 

FERC defines “avoided cost” as the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate or purchase from another source. The rate paid to QFs by the utility must also be just, reasonable, and non-discriminatory. Under FERC’s regulations implementing PURPA, a QF has the option to provide energy or capacity or both to a utility pursuant to a legally-enforceable obligation. State regulators often implement PURPA by requiring regulated utilities to offer standard contracts to QFs with pro forma terms available for ready execution (i.e., “standard offer contracts”). If a QF elects to obtain a contract for energy or capacity or both, the QF may determine, prior to the specified term of the contract, to be paid rates based on either: (1) the avoided costs calculated at the time of delivery; or (2) the avoided costs calculated at the time the obligation is incurred.” Alternatively, QFs and utilities may agree to different rate, terms, or conditions or sell energy on an as-available basis, with the avoided cost calculated at the time of delivery.

In April 2004, the CPUC opened R.04-04-025 to develop a common methodology, to develop consistent input assumptions and updating procedures for avoided costs across CPUC proceedings, and to adopt avoided cost calculations and forecasts based on this work. 

In September 2007, the CPUC adopted D.07-09-040, which created a new avoided cost pricing methodology and provided general direction for a new standard offer contract (SOC) to be made available to all QFs. 

In December 2010, D.10-12-035 was issued that adopted the QF Settlement Agreement as well as the terms of the SOC for QFs of 20 MW or less and other pro forma standard contracts. In this same year, FERC issued two orders that confirmed that the CPUC may establish different avoided costs for different programs or types of resources and remain in compliance with PURPA. Based on these decisions, the CPUC established a series of programs, including the Renewable Market Adjusting Tariff (ReMAT), CHP Feed-in Tariff, the Net Surplus Compensation (NSC) Program for Net Energy Metered (NEM) rooftop solar facilities, and the Bioenergy Market Adjusting Tariff (BioMAT), among others. 

In 2011, FERC granted the petition by PG&E, SCE, and SDG&E to terminate the mandatory purchase obligation for all QFs in California over 20 MW in size, given the QF Settlement Agreement.

In 2012, a solar developer, Winding Creek Solar LLC, sued the CPUC, alleging that California’s ReMAT Program was not compliant with PURPA.

On December 6, 2017, a Federal District Court found in Wind Creek Solar LLC v. Carla Peterman, et al. that the CPUC's standard contract for QFs of 20 MW or less failed to provide QFs the option to choose energy rates determined either at the time of contract execution or at the time of product delivery. As a result, the court also found that the ReMAT Program did not comply with PURPA because there was a cap on procurement and because the prices that results from the ReMAT auction are not avoided costs. Soon after, the CPUC suspended further operation of the ReMAT Program. 

On August 1, 2018, an Order Instituting Rulemaking (OIR) was issued to consider changes to the state’s existing implementation of PURPA for the state’s IOUs, including consideration of the adoption of a new standard offer contract (SOC) that will be available to any QF of 20 MW or less seeking to sell electricity to a CPUC-jurisdictional utility. This rulemaking may reassess the avoided costs and consider adoption of a price to be paid at the time of delivery where a QF has opted to sell as-available energy to the utility without a contract. For the new QF SOC, the CPUC proposed to start with the non-price terms provided in the QF SOC and then consider four alternative avoided cost pricing options for QFs. Overall, it looks like the scope of the OIR is intended to be narrow to determine the appropriate avoided cost for energy and capacity for QFs, especially in response to the Staff Pricing Proposal, which proposes the following four avoided cost price options for QFs seeking a contract:

• For the energy at time of delivery price option, Staff proposes to use hourly prices from the CAISO’s day-ahead market for energy. This same pricing methodology would apply to energy provided as available to a utility by a QF 20 MW or less with no contract.

• For the capacity at time of delivery price option, Staff proposes to use bilateral RA prices for yearly capacity payments, with the RA capacity prices shaped to time periods based on generation capacity cost allocation factors adopted by the Commission and applied to updated TOU periods on a yearly basis.

• For the energy at time of contract execution price option, Staff proposes to use a three-year average of energy prices obtained from the CAISO’s day-ahead energy market. CPUC Staff notes that these prices have remained fairly constant over this time period, that these prices are consistent with long-term prices for energy executed recently, and that prices could increase or decrease, depending on the penetration of renewables (which could exert downward pressure on market heat rates and prices) and fuel prices (which could exert downward or upward pressure on prices).

• For the capacity at time of contract execution price option, Staff proposes to use either (1) average prices from publicly available bilateral RA contracts, or (2) the capacity prices provided in the existing SOC for QFs 20 MW or less, with time-of-day adjustments.

On November 2, 2018, a Scoping Memo was issued that agreed with the OIR’s scope of the proceeding but also added two issues around the cost allocation and duration of contracts at the request of parties. The IOUs and QFs jointly filed a proposal in response to the Scoping Memo to recommend the following terms to be included in the new SOC:

• Use the QF/CHP Settlement PPA for facilities 20 MW and under as the base form of agreement (which would apply to scheduling coordinator, energy scheduling, and interconnection provisions) - the seller would have an option to be the scheduling coordinator, but the buyer would be the default scheduling coordinator if option is not exercised

• Set minimum 12-month term and maximum 36-month term due to significant changes and uncertainty in California electric market

• Set energy price at time of execution based on three-year historical pricing at the PNode of the resource, subject to a collar equal to the Energy Trading Hub (NP/SP 15) price +/- 10%

• Set capacity price at the average of prior three years CPUC annual report for applicable RA month in the zone where the project is located

• Set net contract capacity based on actual monthly NQC value as published by the CAISO awarded towards buyer’s RA compliance requirement

• Establish no obligation for buyer to provide substitute RA

• Use “take or pay” economic curtailment provisions consistent with existing RPS agreements

The joint parties also urged the CPUC to lift the ReMAT suspension and direct SCE and PG&E to restart their programs. With the QF/CHP Settlement PPA as the basis for the new SOC, the proposal would make the ReMAT PPA to be available through December 31, 2020.

On October 4, 2019, FERC issued a Notice of Proposed Rulemaking (NOPR) that would consider energy prices in a QF contract to vary over time in order to avoid locking in above-market prices.

Standard Offer Contract (SOC) Reform

On October 22, 2019, a Ruling was issued to consider the appropriate contract duration for PURPA facilities. On the one hand, the contract duration for a new QF should be long enough to support the financing of a project, and it is not clear from the record that three years is adequate for that purpose. On the other hand, an unnecessarily long contract duration can result in higher costs to utility ratepayers, and it is not clear from the record that a 15-, 20-, or 25-year contract is necessary. More information is sought on the record, but the CPUC has also shared their preliminary review of contract lengths for new renewable and CHP projects.

Many QF parties responded that contract duration plays a role in the financeability of projects and can depend on the size, location, and type of projects (e.g., renewables versus cogeneration), as well as considering the tradeoffs between higher price and shorter duration versus lower price and longer duration. The IOUs and the QF parties that were part of a joint settlement proposal on November 14, 2018 agreed to a three-year maximum term for fixing energy prices based on historical energy prices due to the little “harm” customers would face as future energy prices fall but cannot be predicted accurately. The IOUs indicated that they would exit the settlement proposal if contract durations are made longer than three years. Winding Creek and GPI, however, opposed the joint settlement between the QF parties and the IOUs for three-year contract durations because it only benefits already-existing QF projects seeking new contracts, not new projects, and instead recommended options of 10, 15, and 20 years.

On April 3, 2020, a PD was issued that proposed to adopt a new SOC for qualified developers that would establish upfront prices and stay in place for up to 12 years. In comments to the PD, CalWEA and Solar Electric Solutions recommended that the use of five-year-historical pricing methodology in the context of 7- and 12-year contracts is not reasonable and is almost guaranteed not to reflect avoided cost for 12 years. TURN and the IOUs also recommended the suspension of new SOCs at a certain MW threshold (e.g., 250 MW) in lieu of reducing contract terms, as they preferred; otherwise, they feared a “rush” for the new SOCs. PAO and the IOUs both commented on the need to suspend the new SOCs pending the determinations made in the active PURPA NOPR at FERC.

On May 7, 2020, D.20-05-006 was issued that modified the SOC to support small renewable facilities, in compliance with PURPA and in support of the state’s renewable goals. Specifically, the following was adopted for qualifying facilities of 20 MW or less in capacity:

• SOC contract terms are set at 12 years in length for new QFs and at 7 years for existing QFs: Recent energy procurement contracts by LSEs have terms that range from 10 to 20 years. The 12-year contract term was set to balance the interests of project development with aligning costs with changing market conditions.

• Avoided costs for energy are based on a 36-month rolling average wholesale market prices at LMP nodes calculated on an hourly basis (i.e., reasonable proxies): The decision determined that CAISO day-ahead prices have been stable over the past three years and are consistent with long-term renewable energy contracts. LMP pricing for energy reflect system marginal energy cost, marginal cost of losses, and marginal cost of congestion.

• Prices are determined for peak hours, partial peak hours, and off-peak hours by month and are limited by the NP15/SP15 trading hub, with a 10% collar: This approach takes daily and seasonal peak periods as well as individual and aggregate value of energy from the QFs on the utility’s system into account.

• Avoided costs for capacity is derived from five-year look-ahead for IOU RA prices published annually by the CPUC: The weighted average price for competitively bid RA contracts accurately reflects IOU avoided cost of capacity. Capacity pricing should be based on the most recent Energy Division RA Report which is updated annually.

• RA capacity prices are allocated to seasonal and TOU periods based on a Capacity Allocation Factor (CAF): The $/kWh capacity value will thus be determined using the following formula: Capacity ($/kWh) = (CAF/Hours) * RA Price ($/kW-year). This value is escalated annually by 2.5% for fixed-price contracts.

With this decision, the CPUC rejected the Joint IOU Proposal to limit contract lengths to a range of 12 to 36 months, which the IOUs argued would ensure that ratepayers are not burdened with avoided energy costs in the SOC that are not in line with current market conditions. The decision also rejected arguments by Winding Creek and GPI to set even longer contract terms (20 years). Notably, costs of QF contracts will be allocated to all LSEs through the Power Charge Indifference Adjustment (PCIA) charge.

Relative to the PD, the decision was revised to have averaged prices to establish the energy price being based on the prior three years of data (instead of rolling five-year historical averages), recognizing the growth of CCAs have impacted the load requirements of the IOUs who would be required to pay for PURPA procurement. The energy price available at the time of contract execution will also be updated monthly to reflect changes in market conditions but will remain the same for the term of an executed contract where a QF opts for the avoided costs to be calculated at the time of contract execution. The decision also directed basing energy pricing on the Pricing Node instead of the Aggregated Pricing Node.

For storage, this represents encouraging news, especially as the avoided cost methodology adopted in the decision would reflect dynamic, time-based system needs, which incentivize the development of a co-located battery system that the IOUs would be subject to these “must-buy” obligations from QFs. However, as CESA understands it, there is still some ambiguity as to whether a co-located battery system that is charged with renewable energy should be considered a QF. This is an issue that is being addressed in the new PURPA NOPR at FERC, where ESA is seeking clarifications. In addition, it is not clear whether the battery should be considered a part of the solar QF or instead counted as a separate QF, and whether the nameplate capacity of the battery should be added to the capacity of the solar facility to determine QF eligibility. According to some legal analysis, a FERC case (Luz Dev. & Fin. Corp. 51 FERC ¶ 61,078 (1990)) established that solar-plus-storage is a QF. Thus, at this time, especially as certain PURPA programs such as ReMAT explicitly exclude storage in the tariff, this PURPA decision will not be an immediate driver for co-located renewable and storage systems, but it may open up with clarifications from FERC.

Pursuant to D.20-05-006, the IOUs submitted advice letters implementing the new SOC for 20 MW or less eligible QFs, where developers are offered a choice of fixing the contract price at the time of execution (e.g., As-Executed Option), or electing to have the price for its electricity determined at the time of delivery (e.g., As-Delivered Option). Using weighted average prices from the 2018 RA Report and allocation factors, hourly RA “capacity prices” or payments are heavily concentrated in the peak summer hours as shown below.

However, there are some differences in implementation across the IOUs. For example, PG&E proposed adopting peak TOD periods from 7-8am and 5-10pm from Monday through Saturday. Notably, all three IOUs added two new provisions that storage-paired QFs would be allowed so long as they adhere to the prohibition against charging from the CAISO-controlled grid (Section 9.02 and 9.04). Any request to partially charge from the grid would need to be mutually negotiated and be submitted for CPUC approval via a Tier 2 advice letter. Pursuant to the decision, the IOUs are required to submit updated energy prices to publish new SOCs. 

In protests,  PAO found issue with the inclusion of energy storage-paired QFs in the SOCs, even though the PURPA decision did not address such paired QFs and, consequently, it did not authorize the IOUs to modify the QF SOC as such. PAO added that the CPUC did not contemplate or make judgments about the legal issues of including such proposed modifications. The IOUs disagreed with PAO’s assertions and added that grid charging could be allowed but would require contract negotiation. Meanwhile, CalWEA and Vote Solar advocated for compensating RA payments proportionately for providing a portion of the QF’s NQC. The IOUs, however, disagreed with this proposal because it would adversely affect the ability to manage RA positions and require the purchase of replacement RA.

Ninth Circuit Court of Appeals Decision

On July 29, 2019, the Ninth Circuit Court of Appeals issued a decision on the Winding Creek Solar v. CPUC case upholding the decision of the US Northern District Court that resulted in the injunction suspending the ReMAT, which has been closed for over 18 months. The court reasoned that the ReMAT standard contract was not PURPA-compliant because the standard contract’s pricing mechanisms are based on fluctuating variables. This is an important win for small renewable developers, who subsequently submitted a letter to the CPUC to issue a PD in this proceeding before year-end. This key decision originated from a challenge by Winding Creek Solar against the CPUC in June 2013, arguing that ReMAT was not compliant with PURPA – intended to drive the IOUs to purchase more power from small renewables generators – due to a cap on the volume of energy that the IOUs had to purchase from QFs. However, in a notice issued on May 8, 2015, FERC found the ReMAT to be compliant and thus declined to initiate an enforcement action because the CPUC also offered a standard contract, which did not place a cap on the amount of power an IOU could purchase from a QF.

Renewable Portfolio Standard (RPS) Program

Background

The California RPS program began with a mandate requiring all retail sellers to provide 20% of the electricity they sold to retail end-user customers from RPS-eligible generation by the end of 2017, pursuant to SB 1078 in 2002. Subsequently, SB 2(1X) was passed in 2011 that set a new target for retail sellers of 33% by 2020 and revised the procurement, compliance, and enforcement frameworks for the RPS program, and AB 327 in 2013 provided authority for the CPUC to increase the required percentage of RPS-eligible electricity provided by retail sellers to their customers. The CPUC has not exercised this authority to date. Most recently, in 2015, SB 350 enacted changes to the RPS program that increased the required RPS percentage to 50% by 2030, set a 65% long-term contracts requirement of RPS procurement beginning in 2021, and modified the rules for carrying over excess procurement from one compliance period to later compliance period. 

The RPS program encourages investment in the development of new utility-scale renewable energy facilities to meet the electrical demands of California. RPS is a market-based program where compliance is determined by the quantity of Renewable Energy Credits (REC) acquired (1 REC = 1 MWh). Eligible renewable generation facilities may be located anywhere within the Western Electricity Coordinating Council (WECC) region, extends from the Canadian provinces of Alberta and British Columbia to the northern part of Baja California, Mexico, and encompasses the 14 western U.S. states in between. These facilities are permitted to sell RECs to California retail sellers to meet their RPS obligations, provided the facility meets all RPS eligibility criteria established by the CEC.

The CPUC’s implementation of the RPS program complements the RPS program administered by the CEC, as well as supports California’s climate change policies. The CPUC’s compliance process is completed after the CEC verifies RPS-eligible procurement from renewable energy facilities. The CPUC establishes program policy within its RPS rulemaking proceeding and implements legislation through its CPUC decisions to ensure that electricity retailers comply with CPUC rules and State law.

California’s RPS program defines all renewable procurement acquired from contracts executed after June 1, 2010 into one of three portfolio content categories (PCCs). The PCC requirements are instrumental in determining a retail seller’s compliance with the RPS program.

• Category 1: Bundled RECs from facilities with a first point of interconnection within a California Balancing Authority (CBA), or facilities that schedule electricity into a CBA on an hourly or sub-hourly basis. For Compliance Period 3 (2017-2020), retail sellers are required to procure at least 75% of their portfolio from PCC 1 resources.

• Category 2: Procurement which bundles RECs with incremental electricity, and/or substitute energy, from outside a CBA. Generally, Category 2 RECs are generated from out-of-state renewable facilities and require a Substitute Energy Agreement that details the simultaneous purchase of energy and RECs from an RPS-eligible facility.

• Category 3: Unbundled RECs that do not include the physical delivery of the energy attached to the REC. Generally, Category 3 RECs are associated with the sale and purchase of the RECs themselves, not the energy. For Compliance Period 3 (2017-2020), retail sellers are required to procure no more than 10% of their portfolio from PCC 3 resources.

RECs that are not used to fulfill RPS obligations in one period may be “banked” and used in subsequent compliance periods. SB 2 (1X) (Simitian, 2011) established the ability for a retail seller to carry over procurement from one compliance period to another. Beginning in the 2021-2024 compliance period, pursuant to SB 350, all excess PCC 1 RECs can be banked, regardless of whether they are associated with short- or long-term contracts; no PCC 2 or PCC 3 RECs can be banked.

Annual Reports

In November 2018, the CPUC staff published its annual report of California's RPS Program. Each of the three large IOUs executed RPS contracts to meet the 33% requirement by 2020 (PG&E at 33%, SCE at 32%, and SDG&E at 44% in 2017) and are forecasted to reach 50% by 2020. The "over-procurement" was attributed to reduced load from DERs and customer migration as well as the IOU strategy to hedge against project failure in the early years of the program.

The CCAs, meanwhile, will have an immediate procurement need of approximately 6,900 GWh beginning in 2020. In 2017, all renewable portfolios were 74% wind or solar on average.

Small and multi-jurisdictional utilities (SMJUs) were also highlighted for needing significant RPS procurement for Compliance Periods 3 (2017-2020) and 4 (2021-2024), with BVES, Liberty, and PacifiCorp standing at 27% in 2017. 

Notably, RPS contract prices fell by 7.5% on an average annual basis from 2007 to 2015, reaching a historical low average annual contract price of $47/MWh in 2017. 

While the IOUs are well-positioned to meet the 65% long-term contracting requirement (10 or more years) by the end of 2024, the CCAs collectively need to procure more RPS resources under long-term contracts to meet this requirement, standing only at 45% with only three CCAs out of 19 currently in a compliant position. The situation for the electric service providers (ESPs) were worse, as only one ESP (UC Regents) met this requirement and they currently only stand at 10% of the requirement satisfied. 

Annual RPS Procurement Plans

Background

Every year, each load-serving entity (LSE) is required to submit annual procurement plans outlining how they will meet their procurement obligations, manage various risks (e.g., contract, financial), etc. 

2020

On May 6, 2020, a Ruling was issued directing retail sellers, among other things, to address whether and how they are considering advanced emerging technologies such as hybrid battery storage, offshore wind, or other technologies, especially considering the 2020 Reference System Portfolio. The long-term contracting requirement for RPS resources (65% of portfolio for the 2021-2024 compliance period) was also a key theme of the plans.

On June 29, 2020, LSEs submitted their draft 2020 RPS Procurement Plan. The IOUs generally forecasted a long RPS position through 2027 and thus did not plan to conduct a 2020 or 2021 solicitation. This was not surprising given that the IOUs have not held an RPS solicitation since 2016. On the other hand, they also discussed how they view a need to hold this position until decisions are made in the IRP proceeding for resource procurement needs and the PCIA proceeding around portfolio optimization to sell their excess RPS resources to the CCAs. The IOUs requested the option to conduct a solicitation if needed, depending on the aforementioned regulatory decisions, and discussed how they may consider procurement of RPS-eligible resources to meet other needs, such as reliability needs or to comply with procurement mandates (e.g., BioMAT Program). Many CCAs indicated that they are considering the impact of curtailment and negative pricing on its planned individual portfolio and factors potential curtailment into its long-term planning, but the regulatory uncertainty for capacity valuation and market participation have created some risk in CCAs contracting for hybrid and co-located resources. The viability of adding storage to existing solar facilities was being actively explored. The Joint 2020 Long-Duration Storage RFI was cited by the CCAs as part of their efforts to look at renewables integration needs for storage with eight or more hours of duration, as instructed in the 2019-2020 Reference System Portfolio, with many indicating that they will follow-up with a joint RFO for long-duration storage technologies to be potentially issued in August 2020.

• Clean Power Alliance (CPA) of Southern California plans to issue a 2020 Clean Energy RFO to procure more RPS-eligible resources to meet the RPS and System RA requirements. Previously, CPA procured 120 MW of RPS-eligible resources and 250 MW of storage in their 2019 Clean Energy RFO.

• Desert Community Energy (DCE) reported that it is prioritizing the pairing of storage technologies with solar and wind resources in its 2020 Long-Term Renewables RFO issued in May 2020.

• East Bay Community Energy (EBCE) expects to issue an additional solicitation for renewable energy and storage in the second half of 2020 to secure incremental volumes to meet its RPS requirements. EBCE’s 2018 RFP required all submissions to include energy storage and its 2020 RFP will ask the same and encourage a high degree of variation in storage offers so that EBCE could have a more robust understanding of storage opportunities and configurations that might be available.

• Redwood Coast Energy Authority (RCEA) is considering the addition of an energy storage incentive to be incorporated into the second phase of its Feed-in Tariff (FIT) program to enhance the reliability contribution of RPS-eligible resource types, sized up to 1 MW per project.

• San Jose Clean Energy (SJCE) will soon release a joint long-term RPS solicitation with Peninsula Clean Energy (PCE) for projects with in-service dates commencing no later than 2024. SJCE is evaluating the possibility of implementing a feed-in tariff (FIT) program under which SJCE would agree to enter into PPA from customers who build renewable power resources on their buildings or adjacent lands (and who choose not to use those resources in the NEM program). The earliest that the implementation of such a program would happen would be in late 2021 or 2022.

ESPs also indicated that they are looking at energy storage, with only a few identifying specific plans to include them in their procurement plans (e.g., adding storage to existing solar facilities) and with many viewing storage as a “new” and “emerging” technology:

• Calpine Power America has two of its customers who are in the late stages of negotiation to add a 50 MW storage facility to its new solar asset. No new customers are anticipated.

• Constellation New Energy discussed how it issued an RFI for long-term renewable energy integrated with storage but expressed its view that the technology is too expensive and emerging.

Finally, among the multi-jurisdictional utilities, Liberty CalPeco reported that it plans to leverage the ITC by expanding the Luning Solar Project by adding up to 70 MW of solar and 70 MW of storage. Liberty CalPeco will request CPUC approval of the Luning expansion project later this year via a Tier 3 advice letter.

In opening comments, LSEs did not object to the new filing requirements but they sought to ensure opportunities to clarify requirements and cure deficiencies, especially if any new requirements are unclear or ambiguous, or if inadvertent errors are made in these complex filings. In addition, scheduled penalties should be applied for content deficiencies on final, not draft, RPS procurement plans. However, suppliers held a different view, with AWEA-CA pushing for more commitment or specificity on how LSEs will meet their long-term contracting requirements, adding that penalties could be priced appropriately to incent long-term contracting.

2019

On April 19, 2019, a Ruling was issued that set the scope and schedule for submission and review of 2019 RPS Procurement Plans. Importantly, the plans must include an assessment about how the proposed renewable energy portfolio will align with expected load curves and durations, as well as, how it optimizes cost, value, and risk for customers, which may present opportunities for LSEs to begin considering paired storage resources. In addition, all new CCAs and ESPs are required to file RPS Procurement Plans when they register with the CPUC or 90 days prior to commercial operation, whichever is first.

On August 7, 2019, D.19-08-007 was issued that denied the request for waivers and imposed penalties for non-compliance on Liberty Power ($431,000) and Gexa ($1.7 million) since these entities did not meet their burden of proof of showing entitlement to waivers. The decision rejected Liberty’s justification for non-compliance, finding that it could have bought more expensive PCC 1 RECs instead of focusing on small quantities of fixed-price PCC 2 RECs, which turned out to be scarce and limited in availability. As a result, the decision determined that Liberty’s non-compliance was within its control since a simple solution of procuring readily available (if more expensive) PCC 1 products would have eliminated the problem.  As for Gexa, the decision determined that Gexa’s arguments do not warrant a waiver – i.e., that it was not required to have a long-term contract because it entered the market in the final year of the compliance period, and that its own interpretation that a “requirements contract” meets the long-term contract requirement should govern. Specifically, in rejecting these arguments, the decision discussed how D.12-06-038 did not exempt sellers from compliance with the long-term contract in any year and how Gexa’s three-year contract with NextEra Power Marketing never met this ten-year requirement.

On June 21, 2019, annual RPS Procurement Plans were submitted by 41 LSEs, which collectively proposed 2,500 MW of new RPS-eligible resources by 2023, with approximately 2,044 MW from CCAs. In line with the CPUC highlighting in the IRP proceeding how most new renewable procurement will occur from CCAs, each of the IOUs indicated that they will not procure renewables in 2019 and will instead focus on selling RECs due to falling or migrating load from BTM load-modifiers (e.g., EE, PV) and CCA formation. Notably, SCE forecasted having excess RECs at least through 2028 without the use of its REC bank and beyond 2030 if it uses the REC bank for compliance purposes. Meanwhile, a highlight from the RPS Procurement Plan of Liberty CalPeco was its intent to have 100% of its renewables be utility-owned. 

In comments, PAO and the IOUs focused on implementing an RPS cost containment mechanism, while AWEA and IEP requested that clearer insight be given to the collective net short position for new renewables and reiterated their concerns about LSEs meeting their long-term requirements by January 1, 2021. CalWEA recommended that the CPUC provide clear guidance on the level of curtailment that should be anticipated by LSEs since unanticipated curtailment beyond the control of the retail seller is one of the few reasons listed in the RPS statute as a legitimate excuse for RPS non-compliance and to ensure LSE procurement plans produce plans similar to those in the IRP. To this point, the IOUs and CCAs opposed the use of IRP curtailment rates that are determined on a forecasted aggregate basis and is not useful for specific LSEs. CalWEA also recommended that the CCAs should be directed to use their economic curtailment rights to avoid negative pricing and to incorporate expected curtailment into procurement planning margins instead of avoiding economic curtailments to ensure compliance with RPS requirements, as MCE suggested.

Going forward, it will be important to ensure alignment and incorporation of RPS Procurement Plans with the LSE’s IRP Plans. Many parties supported a recommendation where IRP and RPS Plan inputs were the same or integrated into the same filing during “even years” when both are required of LSEs: These sections include the following:

• Summary of recent regulatory or legislation changes and responsiveness to policies, regulations, and statutes

• Alignment with load curves

• Portfolio diversity

• Lessons learned

• Quantitative information

• Minimum margin of procurement and curtailment

• Safety considerations

The CCAs and ESPs, however, opposed the inclusion of the statutorily-mandated sections from the RPS Plans in the IRP Plans, as well as the requirement for CCAs to submit their bid solicitation protocol and price adjustment mechanism information through an advice letter process, explaining that this information should be information-only and not be subject to CPUC approval.

On September 18, 2019, D.19-09-007 was issued that accepted and approved the 2018 RPS Procurement Plans of six new CCAs (City of Baldwin Park, City of Commerce, City of Hanford, City of Palmdale, City of Pomona and Western Community Energy) but required additional information in 2019 Plans, including cost quantification of planned resources. These CCAs, who already submitted their draft 2019 RPS Procurement Plans, will need to make corrections and modifications to these plans to provide the additional, required details.

For the 2018 plans, however, the CPUC was lenient with these new CCAs since new customers will not be served until 2020. In response to the PD, the IOUs in particular insisted on all LSEs being required to adhere to all statutorily-mandated sections in RPS Plans, including cost quantification of planned resources, but the CCAs and ESPs disputed whether that was statutorily required.

The decision also reaffirmed that the CPUC has the authority and duty to collect price information and ensure safe and reliable long-term procurement of energy resources, citing the PCIA decision (D.18-10-019).

On December 30, 2019, D.19-12-042 was issued that approved the LSEs’ 2019 RPS Procurement Plans. Notably, the decision granted the IOUs’ request to forgo solicitations in 2019 and allowed their selling of RPS volumes due to the decreasing load share to CCAs. Each of the plans of the CCAs and ESPs was approved, but additional information was requested. The decision commented on the “medium” concerns with the long-term contracting requirement for AVCE and SJCE and “serious” concerns with the same requirements for many small CCAs, who were also the subject of deep concern for not even beginning or indicating plans for RPS procurement. Similar concerns were identified for ESPs.

The CPUC made a number of other long-term determinations in this decision that could apply to future procurement plan cycles. First, the decision directed the LSEs to combine IRP and RPS filings for upcoming cycles. Second, the decision affirmed the need to obtain cost information to inform the Legislature and to support the CPUC’s role in IRP and RA planning. Third, the decision affirmed the need to provide curtailment data in the RPS procurement plans since the IRP only presents aggregated data and does not reflect the location-specific and LSE portfolio impacts of curtailment. Finally, the decision declined to give the IOUs a “blank check” for REC trading and sales through pre-approval.

On January 30, 2020, each LSE revised and submitted final 2019 RPS Procurement Plans where many procurement plans discussed how they are exploring the potential for storage to support portfolio diversity and renewable integration needs, though without firm commitments or plans to do so. Valley Clean Energy Alliance (VCEA), a CCA located in Davis, CA, indicated that they will issue a renewables and storage RFO in Q1 2020.

2018

On June 21, 2018, a Ruling was issued that laid out the schedule and identified the issues to be considered for the annual RPS procurement process where the procurement plans will be approved with a decision by the end of the year. The 2018 RPS Procurement Plans must include all information required by statute, including quantitative analysis supporting the retail seller’s assessment of its portfolio and future procurement decisions. The descriptive assessment should consider, at a minimum, a 20-year time frame with a detailed 10-year planning horizon that takes into account both portfolio supplies and demand, as well as information and updates on project development status, potential compliance delays, risks in the RPS portfolio, and economic curtailment provisions. The LSEs were also directed to identify in their proposed 2018 RPS Procurement Plans the assumed minimum margin of procurement above the minimum procurement level necessary to comply with the RPS program to mitigate the risk that renewable projects under contract are delayed or terminated.

On June 28, 2018, the IOUs requested an extension on the 2018 RPS Plan schedule due to the PCIA reform decision (targeted for August 2018) likely changing the RPS need and procurement strategies for each LSE. Specifically, their preferred schedule was to delay the filing of proposed RPS procurement plans until 60 days after the final PCIA reform decision in R.17-06-026. The CCAs responded as neutral to the IOUs’ request, acknowledging the possibility of over-procurement if RPS planning and procurement occurs before finalization and implementation of PCIA reform but also expressing concern about the open-endedness of the IOUs’ proposal. IEP and LSA both strongly opposed the extension request by the IOUs, recommending instead that LSEs explain in their plans how different PCIA outcomes could impact their procurement approaches and strategies. Furthermore, they highlighted how CCAs and ESPs are still behind on their long-term procurement requirements and commented that delaying RPS procurement only results in higher-cost renewable resources given the phase-down schedule of the Federal ITC and PTC.

On July 9, 2018, the ALJ granted the extension in an email ruling that essentially extended the deadlines for each task by about a month. The CCAs and ESPs filed their own motions separately and were granted a similar type of extension. In summary, the RPS procurement plans will have their schedule shifted to a small degree to accommodate the PCIA matter as well as to allow the IRP filings in advance of the RPS procurement plans, which should serve as the procurement vehicle to potentially source the resources needed from their IRP filings.

On August 20, 2018, each LSE filed its 2018 RPS Procurement Plans, where they each provided an overview of their RPS position, current development activities, planned procurement, bid solicitation protocols, and other procurement strategies. Most LSEs reported having achieved their RPS targets and did not report any expected compliance delays, though it appears that some LSEs may have trouble reaching their long-term contracting requirements by 2021 due to their reliance on short-term contracts and spot markets for RPS compliance.  SCE indicated that it does not propose to hold a 2018 RPS solicitation, unless its preferred scenario is adopted in the IRP proceeding. Notably, SCE argued for the elimination of TOD factors in the LCBF valuation because it is unlikely to serve as an incentive to shift power production. CESA also observed that there are a lot of new CCAs that have not contracted for or procured any RPS resources. Among the LSEs, there were a few that indicated intent to procure in the near term, such as Liberty CalPeco, which planned to undertake expedited near-term procurement in the coming months to bridge the May 2019 end of the 2016 NV Energy Services Agreement and then undertake additional solicitations for renewable energy resources and energy storage facilities to achieve the desired low-GHG-emitting portfolio.

Many of the parties representing solar and wind developers filed comments in response that focused on the insufficient long-term contract information provided for RPS resources. The solar and wind parties calculated that only 5 of the 20 operational CCAs have executed any long-term RPS contracts (equivalent to about 1,700 MW or 14% of all contracts), thus requiring approximately 5,000 MW of incremental renewable resources needed under long-term contracts. The Independent Energy Producers Association (IEPA) calculated that new additional RPS capacity from all the LSEs would total up to just 1,319 MW, which is small compared to the magnitude of utility-scale solar and wind resources recommended by the IRP Reference System Plan. As a result, IEPA recommended that the CPUC direct at least 3,000 MW of RPS procurement in 2019 to take advantage of the expiring Federal tax credits. IEPA calculated that the Federal ITC leads to a 35% reduction in solar PV levelized costs, while the Federal PTC leads to a 15% reduction in wind levelized costs. Meanwhile, others commented on the need to update the RPS Procurement Plans upon finalization of the PCIA Decision. However, the LSEs pushed back that procurement should not be done for procurement sake, considering the IRP Reference System Plan is a long-term plan and does not create a near-term procurement requirement (i.e., aggregated LSE plans do). The LSEs also pointed to how the ITC/PTC have been extended in the past and how the long-term contracting requirement does not need to be met until 2021.

On September 5, 2018, due to the LSEs seeking confidentiality of their procurement plans, IEPA submitted a motion that requested that the CPUC direct the LSEs to aggregate their 2018 RPS plans by November 20, 2018, which will be used to determine whether LSEs are meeting their long-term contracting obligation and compliance with the RPS portfolio content category (PCC) procurement restrictions. IEP also requested information on renewable facility technology, size, procurement mechanism, cost, and level of interconnection. At a high level, these requests are intended to enhance transparency, identify trends, and ease stakeholder burden in reviewing the large number of LSE plans. While wind groups also supported the motion to help the CPUC be informed of potential next steps to ensure compliance, the LSEs all opposed the motion as violating confidentiality rules, duplicating IRP work, and being out of scope given that these are planning, not compliance, filings.

On September 19, 2018, a Ruling was issued that directed each LSE to file and serve updates to their 2018 RPS Procurement Plans to address the recently-approved SB 100. Each LSE submitted their updated plans on October 8, with no new procurement expected outside of some of the new CCAs. Sonoma Clean Power (SCP) provided an update about how it has just contracted for 50 MW of solar and 5 MW of battery storage as the Proxima Solar Energy Center, which is expected to be operational by December 2023. Many of the LSEs discussed how there is no risk in meeting SB 100 requirements and used straight-line trends to forecast out their new long-term compliance requirements in lieu of PQRs adopted beyond 2020. For many CCAs, they indicated that they will need an opportunity to consult their local governing boards, as they have not had enough time to update their procurement plans and strategies around SB 100.

On January 22, 2019, a PD was issued approving the IOUs’ 2018 RPS Procurement Plans. CESA was supportive of the PD. Even though there will be no near-term procurement as proposed by the IOUs and approved by the CPUC, CESA supported the coordination with the IRP proceeding to receive guidance on resource-specific procurement, which could include identify value of some near-term procurement and direct procurement accordingly. Importantly, CESA appreciated the consideration of RPS-paired energy storage issues and comments that the proposed use of two TOD factor options in the PD is a step in the right direction for increasingly considering and valuing the role of paired energy storage resources in RPS solicitations. CESA also encouraged the CPUC to continue to develop and iterate on proposals on the ELCC methodology to effectively quantify/determine the capacity value of RPS-eligible resources paired with energy storage.

See CESA’s comments on February 8, 2019 on the Proposed Decision

Other parties also filed comments with solar and wind parties calling for near-term incremental procurement of new RPS resources in 2019-2020 given the IRP modeling results, Diablo Canyon retirement, and the fact that CCA 100% RPS procurements are voluntary. They also continued to argue that equal RPS rules should apply to all retail sellers, reiterating their points that CCAs and ESPs may not be meeting the long-term contracting requirements. The IOUs supported the level playing field argument, while the non-IOU LSEs made jurisdiction and confidentiality arguments in favor of different standards. All LSEs, however, recommended that the CPUC reject the call for additional procurement in the RPS Program, which they view as being more appropriately addressed in the IRP proceeding. On TOD factors, the IOUs requested that the CPUC allow the IOUs to describe in their informational-only TOD proposals, whether, upon further examination, any of the PD’s recommendations cannot be met due to technical feasibility obstacles or because the underlying data constitutes market-sensitive and/or proprietary information. The IOUs, thus, appear to be supportive of the PD’s determination on TOD factors.

On February 28, 2019, D.19-02-007 was issued without significant modifications from the PD. The decision largely approved the IOUs’ 2018 RPS Procurement Plans, with no incremental procurement being directed beyond existing RPS mandates – i.e., approving the IOUs’ request to forgo holding a 2018 RPS solicitation. PG&E claimed that it delivered 33.0% of its electricity from RPS-eligible renewable sources in 2017 and that it does not plan to hold an RPS solicitation for the 2019 cycle. SCE calculated that 31.6% of its retail sales came from RPS-eligible resources. This year, 2018, would mark the fourth year in a row that PG&E and SDG&E will forgo an annual RPS solicitation; it would be the third year in a row for SCE. The continued lack of IOU RPS procurement, except through the mandated ReMAT and BioMAT programs, is largely due to increases in customers switching to service from CCAs and ESPs, which puts them ‘over’ in their RPS compliance positions. The decision noted that the CPUC “is closely examining the arguments for and against near-term procurement” and is coordinating the IRP and RPS proceedings in that regard.

Among the key issues relevant to CESA, the CPUC accepted the staff proposal’s use of TOD factors for informational purposes as well as for use in LCBF valuations and calculating contract payments. Though the information-only option is not optimal for members as it would not lead to actual higher PPA payments for paired storage solutions, the IOUs are also directed in the decision to develop granular TOD factor information to potential bidders, including factors that could change the TOD factors and a month-hour matrix frameworks as recommended by CESA and as used in APS’ RFPs. These proposals will be required within 90 days of the issuance of the decision (May 29). This is positive for co-located RPS generation and energy storage as it would allow the IOUs to use TOD factors to reflect higher contract payments. PG&E and SCE had pushed for the elimination of TOD factors, so the decision tilted in industry’s favor on this issue. Otherwise, no other energy storage issues were addressed in this decision, including our key ELCC methodological issues.

2017

On May 26, 2017, a PD was issued to establish the filing requirements for the 2017 RPS Procurement Plans. The new requirements apply to the three IOUs as well as the CCAs, ESPs, PacifiCorp, BVES, and Liberty Utilities. 

The Ruling also includes a new proposal to use the Renewable Auction Mechanism (RAM) procurement process, which the CPUC intends to continue as a procurement option given the overall success of the program in procuring the mandated RPS capacity. The main concepts are the following:

• Each IOU will identify at least two (in total) specific locations or geographic boundaries where renewable resources, with or without energy storage, can be interconnected to ameliorate a sub-optimal grid condition, such as underutilization of RPS-eligible generation, prevent renewable curtailment, or provide frequency regulation

• Each IOU will solicit at least 20 MW of one or more resource types

• Each IOU will use a RAM process, with solicitation protocols and contract terms and conditions necessary to support the objectives herein

On July 21, 2017, the LSEs submitted their 2017 RPS Procurement Plans detailing how they will implement and achieve their RPS requirements. The three IOUs do not propose to hold a 2017 RPS solicitation and recommend suspending or changing existing RPS mandates established by the CPUC to avoid unnecessary RPS procurement, due to no procurement need, the preliminary and proof-of-concept nature of the IRP results, and the forecasted load departure to CCAs. PG&E and SDG&E will, however, continue forward with procurement through the Renewable Auction Mechanism as required. ORA, CCAs, and ESPs generally support no RPS procurement for 2017. IEP and the solar/wind parties, on the other hand, argue in favor of 2017 RPS procurement to take advantage of imminently expiring federal tax credits and because of their disputes with the IOUs’ internal load forecasts. CESA believes that the IRP preliminary results do make a strong case for some RPS procurement in 2017, but it is unclear whether the CPUC will do so.

Related to TOD factors, SCE provided information about the times for summer on-peak, mid-peak and off-peak periods and the times for winter mid-peak, off-peak and super-off-peak periods. SCE also provided Product Payment Allocation Factors for each of these periods ranging between 0.69 and 1.24. Similarly, PG&E provided factors for peak, mid-day, and night multi-hour periods (covering all 24 hours) in the summer, winter, and spring seasons (which covered all twelve months). These factors ranged from 0.653 to 1.546. PG&E inserted these factors into executed RPS contracts, where they impact the payment for each hour of production. SDG&E provided TOD factors that included seasonal pricing which covered summer on-peak, semi-peak, and off-peak periods and the times for winter on-peak, semi-peak, and off-peak periods. These factors ranged from 0.54 to 2.64. SDG&E inserted these factors into executed RPS contracts, and at the time of payment, SDG&E used the TOD factor and multiplied it by the contract price. All three IOUs used their proprietary energy price forecasts upon which these TOD factors were based in order to assess the value of RPS bids in their LCBF evaluation.

On December 18, 2017, D.17-12-007 was issued that approved the IOUs’ request to forgo holding a 2017 RPS solicitation given that the IOUs are well ahead of interim targets. For example, the IOUs forecast exceeding RPS requirements through at least the 2017-2020 compliance period. Thus, the decision also authorized the IOUs to conduct solicitations for the short-term (five years or less) sales of RPS volumes, at least for the periods covered by the 2017 RPS Procurement Plans. One of the key issues that CESA was tracking in the 2017 RPS Procurement Plans was the RAM proposal included in a May 26, 2017 Ruling, which required each IOU to identify at least two (in total) specific locations or geographic boundaries where renewable resources, with or without energy storage, can be interconnected to ameliorate a sub-optimal grid condition, such as underutilization of RPS-eligible generation, prevent renewable curtailment, or provide frequency regulation. At least 20 MW would need to be solicited under this proposal. However, the decision opted not to adopt the RAM proposal given the interplay between the RPS and IRP proceedings. Given this decision and the recent IRP decision, it appears that there will not be any additional RPS and energy storage procurement over the next year and any new procurement will have to occur in subsequent RPS compliance cycle.

On January 4, 2018, a Ruling was issued on January 4 seeking comment on how SB 350 impacts determination of RPS penalties for non-compliance with and waivers of RPS procurement requirements to inform a future CPUC decision on revisions to RPS enforcement rules. Specifically, the Ruling is contemplating whether the penalty amount of $50 per renewable energy credit (REC) should be changed, whether the penalty amounts should vary based on Portfolio Balance Requirements (PBR) or Procurement Quantity Requirements (PQR), or whether the penalty amounts should escalate for the length or severity of non-compliance. The Ruling also sought comment on new SB 350 language that would allow entities to seek a waiver of RPS obligations due to unanticipated curtailment of eligible renewable resources or unanticipated increase in retail sales from transportation electrification, so long as the waiver does not result in GHG emissions increase. The growing incidence of retail sellers seeking waivers and “make-up” procurement in subsequent compliance periods has prompted the questions posed in this Ruling.

On February 1, 2018, comments were filed, with the IOUs and ORA not recommending any changes to the existing penalty amounts or caps for RPS non-compliance, which they view would complicate the compliance and enforcement rules. The IOUs also underscored the importance of keeping the GHG emissions measurement to within California to simplify the evaluation and of ensuring the same compliance structures for all LSEs. However, others such as the ESPs favored varied penalty structures based on LSE, PBR, PQR, and/or long-term contract requirements. Generally, all parties agreed that unanticipated renewable curtailment or unanticipated increase in transportation electrification will be captured in the IRP modeling analysis.

2016

On August 8, 2016, the IOUs submitted their 2016 RPS Procurement Plans. 

On December 22, 2016, D.16-12-044 approved the IOUs' 2016 RPS Procurement Plans.

Meanwhile, the Joint IOUs received an extension for filing a Joint Proposal to update the actual ELCC values for use in RPS procurement. The IOUs requested the extension because some of the detailed modeling assumptions for California loads and resources from the 2016 LTPP scenarios and modeling assumptions were not yet available. The update will be provided by April 1 (instead of the original December 15, 2016 deadline.

2015

For the period covered by the 2015 RPS Procurement Plans, only SCE conducted an annual RPS solicitation. All three large IOUs continued to procure through their ReMAT and RAM Programs. The most recent RAM auction was the last and final authorized RAM auction. A total of 1,405 MW was authorized to be procured through six RAM auctions, which resulted in a total of 1,209.8 MW of approved contracts.  

Green Tariff Shared Renewables (GTSR) Program

Background

On September 28, 2013, Governor Brown signed SB 43 into law to enact the GTSR program - a 600 MW statewide program that allows participating utilities customers to meet up to 100% of their energy usage with generation from eligible renewable energy resources. SB 43 provided that 100 MW of the statewide limitation shall be reserved for facilities no larger than 1 MW and that are located in designated disadvantaged communities. As required by SB 43, the IOUs filed applications with the CPUC requesting approval of GTSR programs.

SB 840 (2016) removed the program’s January 1, 2019 sunset date.

The GTSR program structure consists of two elements: (1) a Green Tariff option allowing customers to purchase energy with a greater share of renewables; and (2) an Enhanced Community Renewables (ECR) option allowing customers to subscribe to renewable energy from community-based projects. Under the Green Tariff program, IOU customers have the opportunity to source 50% to 100% of their energy needs from renewable projects procured on their behalf by the IOUs that are new, local, and incremental to RPS procurement. Under the ECR program, IOU customers have the opportunity to contract directly with the developer of an ECR project and subscribe to a portion of the project's output corresponding to all or a portion of the customer's energy needs. The customer will receive a bill credit from the IOU based on its subscription to the ECR project. Any customer can cancel their subscription at any time, and if a customer moves, the subscription moves to a new home. The resource must be larger than 500 kW (but no larger than 20 MW), must be secured through a PPA with the IOU, and be located somewhere in the IOU service territory. No caps are specified for individual programs (i.e., Green Tariff vs. ECR programs).

The IOUs launched the first ECR solicitation in the fall of 2016, which yielded no participants, nor did the spring 2017 solicitation. The fall 2017 solicitations resulted in three new, Community Renewables Projects:

• SCE: 3.0 MW Community Solar Project, in Sheep Creek near Victorville

• SDG&E: 2.4 MW Community Solar Project near Campo (near the US-Mexico Border)

• PG&E: 1.656 MW Community Solar Project in Selma (Fresno County)

Subsequent solicitations indicated modest interest in continuation of the GTSR program, including the following highlights:

• SCE: 3.0 MW Community Solar Project, in Lancaster

• PG&E: 37 MW from 11 short-listed projects (currently on hold)

Of the potential 600 MW in new Shared Renewables contemplated for construction pursuant to SB 43, 73% of the generating capacity allowed in the program remains unprocured. Most of the capacity procured thus far has been for the Green Tariff portion of the GTSR program. Of the 163 MW of power already procured on behalf of the GTSR program, only 87.6 MW are enrolled, leaving 75 MW unenrolled. Only SDG&E is close to full enrollment, and thus likely to procure additional renewables under the new, cheaper renewables contracts.

GTSR Program Implementation Pursuant to SB 43

On January 29, 2015, D.15-01-051 was issued implementing the GTSR program framework and approving the IOUs' applications with modifications. The CPUC directed the IOUs to have advance procurement for the GTSR program under contract by February 2, 2016 and divided the program's statewide limitation of 600 MW of customer participation among the IOUs. PG&E was allocated 272 MW, SCE was allocated 269 MW, and SDG&E was allocated 59 MW as the GTSR program cap for each IOU. The CPUC established environmental justice reservations for each IOU: 45 MW for PG&E, 45 MW for SCE, and 10 MW for SDG&E. The decision described the intent of the community interest requirement to give communities the flexibility to structure their projects in innovative ways that incentivize community participation and developer interest in new projects. The ECR component must encourage, rather than discourage, efforts of municipalities to develop shared community renewables. Other key program design elements adopted include the following:

• Adoption of “community” definition as customers within the same municipality or county, or within ten miles of the customer’s address – an important definition that determines “community interest”

• ECR developers must demonstrate that there are as many subscribers as there are MWs in a project (e.g., a 20 MW project must have at least 20 subscribers)

On May 19, 2016, D.16-05-006 was issued that addressed participation of ECR projects in the Renewable Auction Mechanism (RAM). Community interest requirements were also established as follows:

• An ECR project should demonstrate fulfillment of its community interest requirements within 60 days of notification of contract award;

• At least 50% (by number of customers) and at least one-sixth (by load) of the demonstrated community interest in the project should come from residential customers; and

• As required by § 2833(h), individual subscribers are limited to 2 MW of load.

Customers who have registered their community interest are not actually obligated to enroll. When an ECR project is built and a Commercial Operation Date approaches – as much as two to three years later – the project developer must subsequently market and sell customer shares to the community renewable project at that time.

Program Developments

On December 22, 2017, each of the IOUs submitted advice letters on the future of their GTSR Programs. PG&E proposed to extend its GTSR program beyond January 1, 2019, with the following modifications:

• Allow information about GHG emissions reduction from this program to be provided to customers in marketing materials

• Streamline and simplify the ECR program process, such as simplifying community interest requirements and the procurement process

• Streamline reporting requirements to improve program effectiveness and efficiency

SDG&E proposed to extend its GTSR program for an additional five years from 2019-2023 with a proposed budget of $3.8 million, with the following modifications:

• Allow participants to modify their subscription percentages twice within a year

• Allow NEM customers to participate in GTSR

• Allow ECR solicitations to occur once per year

• Modify the 60-day community interest requirement

• Allow the inclusion of GHG emission reduction benefits in its GTSR marketing efforts

SCE proposed to terminate its GTSR program due to low subscription rates – i.e., 7.53 MW of customers subscribed under the Green Tariff Program and no customer enrollment in the Community Renewables Program – even though SCE has met its advanced procurement mandate pursuant to D.15-01-051 by procuring 60 MW of GTSR contracts. SCE detailed its marketing and outreach efforts but ultimately concluded that the GTSR program is not economically viable. However, SCE stated its intent to submit a new renewables rate proposal to accomplish the goals of SB 43, which established the GTSR program in the first place. 

Several parties supported SDG&E and PG&E’s general extension proposals including TURN, SEIA, NRDC, Sierra Club, CUE, and Clean Coalition. CCSF argued that at a maximum, the CPUC should not extend PG&E’s GTSR program for longer than four years as proposed by SDG&E. None of the thirteen protestants supported SCE’s proposal to terminate the GTSR program. SCE further clarified it would support the continuation of the GTSR program until a viable alternative is implemented.

On September 12, 2019, Resolution E-4940 was issued to address the future of the GTSR Program in response to IOU advice letters submitted in December 2018.

• PG&E’s proposal to remove the community interest and locational requirement is rejected because it is a core feature of program design and inappropriate for an advice letter process.

• PG&E’s proposal to remove the “number of subscribers” challenge is approved because the residential requirement ensures an appropriate mix of residential and non-residential participation.

• PG&E’s proposal to move the demonstration of the residential requirement from 60 days after award notification to the time of commercial operation is approved because it adds more flexibility for developers.

• PG&E’s proposal to have one-sixth of the load come from the residential sector at the time of operation is approved as a “demonstrating” the residential requirement because it adds more flexibility for developers.

• SCE’s request to terminate its GTSR Program is rejected since SB 840 (2016) removed the program’s January 1, 2019 sunset date and D.19-05-031 rejected SCE’s separately-proposed new green energy program.

• SDG&E’s request to extend its program by five years is moot, as SDG&E shall continue the program indefinitely until the program cap is reached.

• SDG&E’s proposal for the community interest requirement as a condition in the PPA that must be met by the developer prior to the start of construction is approved because the timing requirement can be modified as a non-material change.

• SDG&E’s proposal to allow participating customers to modify their subscription percentage up to two times per year is approved because it adds further flexibility for participation.

• SDG&E’s proposal to allow NEM customers to participate in GTSR up to 10% of each IOU’s program cap is approved, and PG&E and SCE are also encouraged to adopt similar structures.

• ForeFront’s request for SDG&E to revise its ECR tariff to clarify that the 2 MW capacity cap be applied on a location-by-location basis rather than an enterprise-wide basis is approved.

• IOUs’ proposals to utilize the Voluntary Renewable Electricity Program (VREP) methodology and TURN’s proposal to utilize the Clean Net Short (CNS) methodology to characterize the GHG emissions of the GTSR products is rejected since those methodologies apply to a portfolio of resources.

  
  

SCE Green Programs Application (A.18-09-015)

Background

On September 26, 2018, SCE submitted an application that seeks authority to implement five new “green energy” programs ($5.87 million) through which SCE’s bundled sales customers may purchase RPS products from SCE under varying terms and conditions, in addition to recovering an estimated $7.3 million for a 10% transition credit bill discount for eligible CARE/FERA customers through 2030. The purpose of the transition credit is to provide low-income participants with an additional benefit to incent them to transition to renewable energy. SCE has summarized the five program offerings as follows:

• New Green Tariff: All of the customer’s energy is sourced by a portfolio of utility-scale renewables projects.

• Plus Green Program: SCE offsets the non-renewable portion of a participating customers’ load with the retirement of unbundled RECs.

• New Community Renewables: Electricity from a dedicated renewable energy generating facility is procured to supply power to a defined community.

• Green Direct: Large business and government customers are supplied by a dedicated third-party renewable energy generating facility.

• Customer-Controlled Renewables: SCE offers Inter-Scheduling Coordinator Trades (ISTs) with large customers that deliver renewable energy into the CAISO’s wholesale market and earning market revenues.

The differences and further detail on the programs are presented below. 

These programs would replace its existing GTSR Programs in 2021. SCE proposed these new programs based on the goal of reducing barriers to customer participation in renewable energy program offerings.

Multiple parties filed protests or responses to the application. PAO, CCAs, and Shell protested based on concerns about cost-shifting between participating and non-participating customers, arguing that the new program should have costs recovered exclusively from participating customers. TURN and CUE had issues with marketing the Plus Green Tariff as a zero-GHG offering due to additionality concerns. Meanwhile, SEIA and Vote Solar supported the diversification of clean energy options but preferred having any new GTSR-type program to be discussed and structured within conversations of ongoing review of current GTSR programs to ensure consistency. The Coalition for Community Solar Access (CCSA) reiterated some of the same concerns and found some of the proposals to replicate the flaws of the GTSR programs, including the bill credit calculation methodology that limits the economic value proposition to customers (e.g., full range of DER values, third-party competition to develop projects).

On January 18, 2019, a Ruling was issued that denied Shell’s motion to dismiss and directed SCE and other parties to file opening and reply briefs. The CPUC found that there are “threshold legal issues” that must be addressed.

On April 19, 2019, a Scoping Memo was issued that will focus on whether the CPUC should approve SCE’s proposal to replace the existing GTSR Program with the Green Energy Programs and whether SCE can terminate the existing GTSR Program without violating current law.

Application Review

On February 8, 2019, briefs were filed. SCE asserted the CPUC’s jurisdiction to implement voluntary utility programs without specific statutory authorization and proposed that it could retain the GTSR program and have the Green Energy Program launch in parallel to promote competition between the programs. SBUA supported SCE’s Green Energy Program and its decision to terminate the GTSR due to low participation rates from the commercial sector, viewing the new application as a more attractive program. However, the CCAs, PAO, TURN, and CUE contended with SCE’s citation of D.15-01-051 as a basis for permanently terminating their GTSR program, pointing also to how SCE must reach its 269 MW cap. PAO, TURN, and CUE recommended that the focus instead be on improving the GTSR program given positive recent trends, including drops in the net residential subscriber premium. The PAO also found it inefficient and a misuse of ratepayer funds to pay for the administration of both programs.

On June 3, 2019, D.19-05-031 was issued that dismissed SCE’s application for approval to replace its existing GTSR Program with five new green energy programs starting in 2021, though the decision did not prejudge the merits of SCE’s proposed programs or preclude SCE or parties from seeking CPUC approval for refinement or modification of the existing GTSR Program. In other words, the CPUC found that the grounds for denying the application is that SCE does not have authority to terminate its existing GTSR Program because the CPUC is constrained by Sections 2831-2833, even though the CPUC has authority to approve voluntary utility programs. D.15-01-051 allowed SCE to file an advice letter to sunset the GTSR Program, which is based on an ordering paragraph of the decision that does not reflect the change in law; the CPUC agreed that there is a distinction between suspension versus termination of the GTSR Program. SCE can, however, elect to submit a new application for its voluntary Green Energy Programs that is not premised on terminating and replacing the GTSR Program. If SCE does file a new application proposing the Green Energy Programs, SCE should address how the Green Energy Programs would coexist with the GTSR Program.

Renewable Auction Mechanism (RAM)

Background

In 2010, D.10-12-048 was adopted that established the Renewable Auction Mechanism (RAM), which is designed to simplify procurement and contracting for renewable resources in the 3-20 MW capacity range, while the Renewable Market Adjusting Tariff (ReMAT) is utilized for the same purposes for resources less than 3 MW in size. The CPUC initially authorized the IOUs to procure 1,000 MW (later expanded to 1,299 MW by D.12-02-035 and D.12-02-002) through RAM by holding four auctions over two years. Resolution E-4582 authorized a fifth auction to take place no later than a year after the close of the fourth RAM auction. Projects that include energy storage are not considered eligible to participate. 

Policy Development

On November 20, 2014, the CPUC issued D.14-11-042 that adopted one additional RAM auction (RAM 6) to close by June 30, 2015. It also addressed PG&E's February 14, 2014 Petition for Modification (PFM) of D.10-12-048 in order to transfer the remaining 200 MW capacity in PG&E's Solar Photovoltaic Program (SPVP) into RAM and two other solicitations. In doing so, PG&E sought to close the SPVP. The PFM was granted with half the remaining SPVP capacity allocated to RAM 6 and the other half transferred equally across 2016 and 2017 solicitations. 

On January 22, 2016, PG&E filed a PFM of D.14-11-012 to eliminate its requirement to conduct Renewable Auction Mechanism (RAM) solicitations in 2016 and 2017, which are required by D.14-11-012 to procure approximately 200 MW as part of a transfer from PG&E’s Solar PV Resources Program. As a result of D.14-11-042, 106 MW was allocated to the 2016 and 2017 solicitations, and there was 31.5 MW of unfulfilled capacity from PG&E’s sixth RAM solicitation. Due to PG&E’s sufficient RPS resources and load forecasts for 2016 and 2017, PG&E argued that it did not need additional RAM solicitations to meet its RPS requirements. 

On August 28, 2017, D.17-08-025 was issued that denied PG&E’s PFM due to California’s 2030 GHG goals, which highlight “an ongoing need to decarbonize California’s electricity supply”. D.17-08-025 also denied the PFM on the grounds that PG&E should be held to their assurances of D.14-11-042 that the RAM was a better procurement vehicle than the SPVP.

On September 28, 2017, the CPUC rejected SDG&E’s request to modify D.10-12-048, D.12-02-002, and D.14-11-042 to terminate its RAM procurement requirement because “it will assist California in reducing GHG emissions”.

Renewable Market Adjusting Tariff (ReMAT)

Background

ReMAT is a tariff that provides market-based adjusting prices for small RPS-eligible generators to sell power to utilities under standard terms and conditions. The maximum eligible feed-in tariff (FIT) project size is 3 MW, which includes a limited exception for hydroelectric facilities (up to 4 MW). 

The CPUC adopted the ReMAT program in 2012 as a new pricing mechanism for the CPUC’s § 399.20 Feed-in Tariff (FiT) Program to implement statutory amendments to Public Utilities Code § 399.20, enacted by Senate Bill (SB) 380, SB 32, and SB 2. The CPUC is required to adopt a standard tariff for electricity purchased from a small renewable “electric generation facility” as defined by § 399.20(b). The CPUC must determine the payment paid under the standard tariff, which must be a “market price” that includes “all current and anticipated environmental compliance costs.” When “establish[ing] a methodology to determine the market price of electricity for terms corresponding to the length of contracts,” the CPUC is required to consider the following:

• The long-term market price of electricity for fixed price contracts, determined pursuant to an electrical corporation's general procurement activities as authorized by the CPUC.

• The long-term ownership, operating, and fixed-price fuel costs associated with fixed-price electricity from new generating facilities.

• The value of different electricity products including baseload, peaking, and as-available electricity.

Electric utilities must offer the standard tariff and associated standard contract to eligible facilities within their service territories, upon request on a first-come-first-served basis, until the electric corporation meets its proportional share of a statewide cap of 750 MW.

Policy Development

On August 28, D.17-08-021 was issued that updates California’s RPS feed-in tariff programs in accordance with AB 1979 (Bigelow) and AB 1923 (Wood). Participation in the feed-in tariff programs has been limited to RPS-eligible generation facilities with effective capacity of up to 3 MW. Pursuant to AB 1979, conduit hydroelectric generation facilities with effective capacity of up to 4 MW and meeting certain other criteria may be eligible for the RPS renewable market adjusting tariff (ReMAT). In other words, the actual delivery of power to the grid must be limited to the 3-MW statutory limit. Pursuant to AB 1923, bioenergy generation facilities with effective capacity of up to 5 MW and meeting certain other criteria may be eligible for the RPS bioenergy market adjusting tariff (BioMAT). This decision implements these legislative provisions for exceptions to the capacity limitations of the RPS feed-in tariff programs. The decision directs PG&E, SCE, and SDG&E to modify their ReMAT and BioMAT tariffs and power purchase agreements to allow the participation in ReMAT and BioMAT of the types of RPS-eligible generation facilities identified by the legislation under the conditions specified.

On September 27, 2017, the IOUs jointly filed an Application for Rehearing of D.17-08-021 to authorize facilities participating in BioMAT and ReMAT to sell power in excess of the statutory 3 MW limit under other CPUC programs. They assert that the CPUC acted without jurisdiction or in excess of its jurisdiction, did not follow the appropriate processes, and made a decision not supported by evidence. D.17-08-021 allowed exceptions to the 3 MW limit to California’s RPS FiT programs in implementing AB 1979 and AB 1923.

On December 6, 2017, a federal district court found that the CPUC’s ReMAT program did not comply with the Public Utility Regulatory Policies Act of 1978 (PURPA) because of the program cap on procurement and because the prices calculated under the ReMAT program are not permissible under PURPA. The Winding Creek Order determined that the prices established by ReMAT’s adjusting pricing mechanism do not calculate “avoided costs” under FERC's regulations, which define “avoided costs” as “the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source.” By the Winding Creek Order, the federal court accordingly granted an injunction prohibiting the CPUC from continuing to apply the Re-MAT program as set forth in the orders initially establishing the ReMAT program, D.12-05-035, D.13-01-041, and D.13-05-034. In accordance, the CPUC suspended the ReMAT program.

On June 26, 2020, a Ruling was issued seeking comments from parties on proposed modifications to the ReMAT Program, after being suspended for an extended period of time and following the issuance of D.20-05-006 that adopted a new QF Standard-Offer Contract (SOC) for QFs of 20 MW or less. By November 2017, before ReMAT was suspended, the IOUs had collectively procured 255.7 MW of renewable power under ReMAT, leaving an additional 238 MW that must be procured to meet their portion of the statewide procurement target; SDG&E appears to have subscribed its proportionate share of ReMAT program capacity, meaning it has met its statutory obligations and no longer plans to re-open its ReMAT Program. In the Ruling, staff proposed that ReMAT resume promptly but that the price adjustment mechanism, program period caps, and bi-monthly program periods be eliminated and replaced with administratively-determined prices by product category with a time-of-delivery (TOD) adjustment, based on IOUs’ recent RPS contract prices.

The fixed contract prices may be updated annually as new RPS contracting information is reported. These prices will be used until each IOU reaches their allocated share of the statewide procurement mandate.

To date, the ReMAT Program has not been a major driver for storage procurement, largely because of the lack of consideration since 2013 when the program was suspended. But much has changed since then where storage should be actively considered. With the PURPA SOC including new TOD factors and considering the use of storage in the IOUs’ implementation advice letters, there may be a new opportunity for paired storage procurement, especially as the peak period has shifted from 12-6pm in 2013 to 4-9pm in 2020. Notably, the Staff Proposal utilized stale RPS contract data to set the avoided cost for ReMAT pricing across the three product categories and seemingly also used old TOD factors, creating concerns of the ReMAT prices not necessarily reflecting current market conditions or similar resources. CESA argued that it is important for the next iteration of the ReMAT Program to consider the role of storage in the resulting ReMAT tariff and PPAs, such as by using the latest TOD factors and by recognizing and compensating for the capacity value of hybrid and co-located resources. In addition, new application and procurement processes should be established to provide project certainty and viability.

See CESA’s comments on July 21, 2020 on the Ruling

Comments were broadly in opposition to the Staff Proposal. Developers focused in the ReMAT Program offered many comments on the modifications to support participation, with general consensus that utility-scale RPS pricing as not being appropriate as the avoided cost for small renewable facilities less than 3 MW in size (i.e., dissimilar economies of scale), for not accounting for pricing diversity among service territories, and for not recognizing differences in investment tax credit (ITC) and production tax credit (PTC) levels. Many also agreed on the use of energy storage and the need to use up-to-date TOD factors. The ReMAT Coalition instead recommended quarterly program periods, changing pricing by increments of 5% rather than $4, $8, and $12 (as being more gradual), and removing the 5-MW program period procurement cap. Vote Solar and Clean Coalition offered different recommendations to use a reverse auction process and adders (e.g., resilience), respectively. CalWEA added that staff should consider reallocation of capacity in product categories as appropriate. Finally, some parties advocated for grandfathering rules for developers who submitted projects in 2013 but was not contracted to be eligible for contracts at $89.23/MWh, which was applicable at the time, due to the substantial investments made at the time.

By contrast, PAO and the IOUs expressed concern with the greater weight to older, higher-priced contracts (2013-2015), with PAO recommending a workshop be held to discuss a new pricing methodology to calculate ReMAT fixed prices. PAO also commented that ReMAT does not need to comply with PURPA regulations since the new QF SOC satisfies the CPUC’s obligation to provide QFs with the option to choose energy and capacity rates determined at the time of contract execution or delivery; in other words, the District Court order gave the CPUC an opportunity to propose an alternative PURPA-compliant program if ReMAT is not revived. PG&E and SCE, meanwhile, recommended the elimination of separate prices for the product categories, which will be addressed through TOD adjustments to the new SOC prices already determined in the PURPA decision (D.20-05-006). Under 15-year terms for the ReMAT PPA, the IOUs each proposed storage components for ReMAT resources. The following is SCE’s proposed ReMAT tariff:

PG&E’s proposed ReMAT tariff is as follows:

With approximately 250 MW of contracted capacity left in the program, the above tariff amendments could be favorable for hybrid solar-plus-storage projects. SCE’s proposal, in particular, presents the highest $/MWh prices for peak-period deliveries, which can only be delivered by solar when paired with storage.

Los Angeles Department of Water & Power (LADWP)

Background

LADWP has set a procurement target of 154 MW of energy storage systems by December 31, 2021.

On December 22, 2016, LADWP released its 2016 Integrated Resources Plan (IRP). The plan included RPS goals of 35% renewable energy by 2020, 55% renewable energy by 2030, and 65% renewable energy by 2036. Importantly, it also included a compliance plan for their AB 2514-directed procurement for energy storage. CESA recommended that LADWP consider more energy storage than just the minimum necessary. CESA also offered arguments that energy storage is cost-effective in many applications today and can provide more value than just renewables integration.

On April 30, 2019, Mayor Garcetti provided the first major update of the LA Sustainable City pLAn in May 2019, after releasing the first such plan in 2015. In this update, the report proposed a New Green Deal for the city. As of January 2019, the report highlighted how LADWP currently has 350 MW of local solar and 1,276 MW of energy storage. The city’s accelerated goals and new targets include the following:

Additionally, the Green New Deal includes targets in many other sustainability areas, including around urban ecosystems, food systems, waste reduction and elimination, waste and resource recovery, local water sourcing, environmental justice, and “lead by example” targets for municipal buildings and fleet vehicles.

Energy Storage Procurements

LADWP has set a procurement target of 154 MW of energy storage systems by December 31, 2021.

On December 22, 2016, LADWP released its draft 2016 Integrated Resources Plan (IRP). The plan included RPS goals of 35% renewable energy by 2020, 55% renewable energy by 2030, and 65% renewable energy by 2036. Importantly, it also included a compliance plan for their AB 2514-directed procurement for energy storage. CESA recommended that LADWP consider more energy storage than just the minimum necessary. CESA also offered arguments that energy storage is cost-effective in many applications today and can provide more value than just renewables integration.

On January 4, 2017, LADWP issued a Request for Information (RFI) related to siting energy storage at their Beacon Solar Plant in Mojave, CA. LADWP is considering leasing a battery energy storage system for a term of 10 years to be commissioned by December 2017, which would provide frequency response, regulation, and volt-var support. LADWP is seeking a performance-based Energy Service Agreement (ESA) for a 25-MVA, 20-MW, 10-MWh lithium-ion battery energy storage system.

On August 15, 2017, LADWP approved an agreement for the procurement, installation, and commissioning of the Beacon Battery Energy Storage System (BESS) at the Beacon Solar Plant with Doosan GridTech for a term of one year and for up to $20 million. The BESS will be a grid-scale 20 MW (10 MWh) lithium-ion battery energy storage system to help LADWP alleviate its use of gas-fired generating units, especially in light of the short-term Aliso Canyon gas curtailment. A total of eight proposals were submitted in response to the RFP. 

On July 23, 2019, LADWP secured approval from the city’s Board of Power & Water Commissioners for a solar-plus-storage project with 8minute Solar Energy. The 400-MW solar and 100-MW battery storage project executed a 25-year PPA at $0.01997/kWh for solar and $0.013/kWh for storage.

LA100 Study

Background

LADWP has set a procurement target of 154 MW of energy storage systems by December 31, 2021.

On December 22, 2016, LADWP released its 2016 Integrated Resources Plan (IRP). The plan included RPS goals of 35% renewable energy by 2020, 55% renewable energy by 2030, and 65% renewable energy by 2036. Importantly, it also included a compliance plan for their AB 2514-directed procurement for energy storage. CESA recommended that LADWP consider more energy storage than just the minimum necessary. CESA also offered arguments that energy storage is cost-effective in many applications today and can provide more value than just renewables integration.

On April 30, 2019, Mayor Garcetti provided the first major update of the LA Sustainable City pLAn in May 2019, after releasing the first such plan in 2015. In this update, the report proposed a New Green Deal for the city. As of January 2019, the report highlighted how LADWP currently has 350 MW of local solar and 1,276 MW of energy storage. The city’s accelerated goals and new targets include the following:

Additionally, the Green New Deal includes targets in many other sustainability areas, including around urban ecosystems, food systems, waste reduction and elimination, waste and resource recovery, local water sourcing, environmental justice, and “lead by example” targets for municipal buildings and fleet vehicles.

LA100 Advisory Group

On February 15, 2018, an Advisory Group meeting was held to provide input and discussion of LADWP’s study of a greener Integrated Resources Plan.  The study team indicated that it will begin to actively consider important study inputs, including: 

• How soon could LADWP’s resource mix be modified to meet 100% clean energy goals by 2040 or by 2050?

• How should clean energy goals be defined?

At the meeting, NREL presented an overview of the study approach, including how system and resource modeling would form the basis of later economic development and environmental impact studies. The scenarios and sensitivities (shown below) will be used in the initial capacity expansion modeling runs. The 100% renewables and load modernization scenarios are the most restrictive in that they do not allow bioenergy, nuclear, new hydro, carbon trading, or carbon capture among the resources that could be selected. Some concerns from stakeholders were raised around taking a least-cost approach to resource selection. NREL has targeted initial scenario results to be completed by November 15 with final results by Q3 2019. The final report will be presented by Q2 2020.

The study will also examine several scenarios involving different combinations of once-through-cooling (OTC) generation retirements and repowering on different timeframes, including full or partial repowering with energy storage and/or other alternatives. Data is being gathered and the model is being developed for the OTC analysis to be completed by July 2018. Finally, LADWP announced that it has renamed its Integrated Resource Plan to the Strategic Long-Term Resource Plan (SLTRP) to distinguish between its internal planning process and the regular IRP filings it must submit to the CEC. The 2017 SLTRP, which will go to the LADWP Board and be filed with the CEC, reflected a plan to achieve a 55% RPS by 2025 and a 65% RPS by 2036, and to add 404 MW of energy storage by 2025. The 2018 SLTRP will apply an extended timeframe to 2050 to match the 100% renewable study scope as a reference scenario.

On June 7, 2018, LADWP hosted a meeting to explore scenarios for high levels of renewables in its study and how energy storage can support such efforts and other reliability goals. NREL presented on their preliminary modeling results that identified a ‘duck curve’ where fossil generators and the Castaic pumped storage plant supplied the four-hour ramp that followed the mid-day overgeneration and found that 80% renewables is an inflection point where the percentage of “unusable renewables” rapidly increases and where the cost of marginal carbon abatement begins to accelerate. While NREL identified the Castaic plant as a great resource to mitigate overgeneration and support reserve requirements, it may be exhausted as the Los Angeles area moves toward higher levels of renewables. Adding 3 GW of 4-hour energy storage was identified as a viable option based on expected cost trajectories where lifecycle costs of combustion turbines are approximately equivalent to the lifecycle costs of some energy storage. However, NREL observed that the current energy storage technologies may be unable to cost-effectively provide seasonal shifting of overgeneration to meet demand in the evening and other seasons.

NREL proposed seven scenarios and two reference cases that incorporates Advisory Group feedback into the proposed final scenarios, such as sensitivities that will look at accelerated 100% renewables compliance, interim targets toward the 100% goal, and the implications of regionalization. Each scenario will start at the same 2030 net renewables goal and then identify the least-cost resources that LADWP could procure to meet the 2050 goal under various scenarios. However, several stakeholders found issue with this approach because LADWP could be making resource investments before 2030 to facilitate some of these scenarios.

Additionally, LADWP provided an update on its current planning process where it is actively considering downsizing the repower of its Intermountain Power Plant (IPP) combined cycle gas turbine plant (CCGT) from 1,200 MW to 844 MW. Additional assessments on transmission and power flow modeling will further inform if and how energy storage solutions can be used. LADWP noted that it is looking at CAES proposals via a Request for Information (RFI) from the Southern California Public Power Authority (SCPPA).

On August 16, 2018, an Advisory Group meeting was held for NREL to present on the various steps in putting together the scenarios, modeling inputs, modeling outputs, and validation and to showcase the extensive and sophisticated tools that they will use, including capacity expansion and production cost modeling. For the carbon emissions assessment, NREL will take a lifecycle approach that will entail a literature review on the lifecycle emissions of generation sources and battery storage. NREL noted that the literature is rather thin on utility-scale batteries. For the OTC study, NREL indicated that it is approaching the final phases of the study, down to 12 potential options which will now go through “constructability” and “metrics” scores. NREL is bounding the potential energy storage options at 5,200 MW of utility-scale energy storage and 261 MW DER energy storage in the LA Basin, with “out-of-basin” solutions not being considered. The energy storage solutions will be four-hour batteries. The “constructability” assessment for battery storage will include considerations of land use, local opposition, fire risk, permits, disposal of chemicals, chemical replacement, and costs.

On November 15, 2018, an advisory group meeting was held to provide a briefing on SB 100, suggested changes to scenarios based on SB 100, an overview of the economic development analysis and power system cost analysis, and a final update to the OTC repowering study. With the scenarios updated and finalized for the 100% Renewable Energy Study, NREL will proceed to conduct the modeling and analysis.

Specifically, NREL discussed how it has updated its scenario matrix to set LADWP’s 2017 Strategic Long-Term Resource Planning (SLTRP) and SB 100 as the reference cases, with alternative scenarios based on different “futures” that all must meet or exceed SB 100 goals, which is a change from the old scenarios matrix the net 100% renewables was only one of the modeling scenarios. The alternative scenarios thus will model how LADWP can reach net 100% renewables by 2030 – a more accelerated goal than the 100% zero-carbon resources goal by 2045 as set by SB 100. Compared to before, NREL also added a new ‘high load stress’ scenario to reflect what could happen if load grows with no improvements in energy efficiency.

It is also important to note that the NREL team is looking at net 100% renewable energy, which matches renewable energy with load annually. Thus, unlike the ‘clean net short’ methodology used in the CPUC’s IRP modeling and LSE plans where zero-GHG generation must meet load on an hour-by-hour basis to be credited with zero GHGs, NREL will look at how LADWP can use renewable energy credits (RECs) to meet their 100% renewables goal. In this regard, the CPUC’s IRP modeling is more favorable to energy storage because overgeneration of renewables is not credited to meeting GHG goals, though LADWP’s IRP approach better aligns with CARB compliance mechanisms. A key interest for CESA will be in providing input into the cost and resource assumptions. NREL indicated that advisory group members will have that opportunity in March 28, 2019, when preliminary study results will be released.

NREL also presented on their approach to cost analysis, which will first involve capacity expansion modeling to estimate investment and operational costs for new resource additions based on hourly dispatch across four representative days. NREL will utilize multiple investment and adoption models: RPM (bulk system generation and transmission), dGen (distributed generation), and DISCO (distribution-scale transmission). Next, production cost modeling will calculate detailed operational costs at the five-minute level based on seven years of dispatch data and identify generational shortfalls and/or additional investments (e.g., transmission investments) needed to address congestion, which are then fed back into the capacity expansion model. Finally, power flow modeling will focus on just a few portfolios from the capacity expansion and production cost modeling to identify any other necessary bulk and distributed infrastructure to mitigate power flow issues (e.g., disturbances, contingencies) and other stressors. LADWP will then conduct a rate impact analysis based on the resulting portfolios. While the capacity expansion model only looks at a small sample of days (even less than the 37 representative days in the CPUC’s RESOLVE model), NREL is taking an approach to create feedback loops, where the production cost modeling may identify issues that are added as “constraints” on a case-by-case basis and then re-run in the capacity expansion model to select a new set of resources. In response to CESA’s questions, NREL commented that curtailment is modeled using PLEXOS and regression techniques, and that hybrid storage solutions are not considered in the model, though the model may highlight the benefits of hybridization since energy storage systems can be located anywhere.

On June 13, 2019, the LA 100 Advisory Group meeting was held for the first time since Los Angeles Mayor Eric Garcetti announced that LADWP will not repower three OTC plans on February 12, 2019 and announced the LA’s Green New Deal on April 29, 2019. Given these new directives from the LA Mayor’s Office, LADWP discussed how it is in the process of developing a new initiative – the Clean Grid LA Plan – that incorporates the Mayor’s no-repowering decision and Green New Deal targets into the 100% study, even though it will continuing having a process for its recurring Strategic Long-term Resource Plan. The guiding principles for the Clean Grid LA Plan are to develop and source local power that is reliable, clean, flexible, and sensitive to rate impacts, while striving toward 100% renewables by 2045 and carbon neutrality by 2050. The Clean Grid LA Plan will be informed by the recently issued RFI for new distributed resources and will be finalized by 2020.

This advisory group last met in November 2018, so there were a number of key changes to the modeling framework, assumptions, and scenarios. NREL discussed their iterative modeling process across their proprietary capacity expansion (RPM), distributed generation and system (dGen), production cost (PLEXOS), and power flow (PRAS) models but noted that it will still only look at eight agreed-upon scenarios given the complexity of different models being used, the interactions between them, and the number of runs needed. In addition to the Mayor’s new directives, LADWP discussed how PG&E’s bankruptcy and other states adopting renewable targets are important contextual factors to consider as NREL proceeds with modeling. Some of the key changes and observations in the modeling include:

• No OTC repowering in any scenario: OTC units, which have 2029 compliance deadlines, are replaced with clean alternative generation. LADWP said that it is in the process of finalizing the previous OTC repowering study but is unclear on if or when it can share the report given the new initiative. Some stakeholders recommended repowering scenarios as a reference case or different repowering options using storage or transmission lines.

• Focus on local sourcing: Most of the scenarios model LADWP for self-sufficiency – i.e., direct control of sufficient LADWP owned and operated assets for energy, capacity, planning reserves, and operating reserves. However, for dispatch, the scenarios will look at LADWP’s assets as well as fully coordinated dispatch leveraging neighboring balancing authorities and load-serving entities (i.e., operational cost savings potential).

• 100% renewable versus 100% net renewable: Some of the scenarios have been set up to test how LA could reach their 100% goal using RECs – i.e., on a net basis – as opposed to making sure all load in the future is met with actual renewable generation, similar to the CPUC IRP’s Clean Net Short (CNS) methodology.

• Most scenarios go beyond SB 100 and Title 24: The Green New Deal put LA on a more accelerated trajectory than SB 100 and have higher electrification goals through 2050 than what has been established in California’s 2019 Building Efficiency Standards through 2022. Based on the Mayor’s directives, many of the scenarios will test a high end-use electrification cases with significant EV and building electrification projections (“beyond code” forecasts). Stakeholders questioned the feasibility and reasonability of 100% electrification.

• Technology and resource costs and performance: NREL discussed how it has three different cost projects using its Annual Technology Baseline (ATB) and how it will use its best-guess mid-case for each resource. However, given the intensive run time and interaction of the multiple models, NREL will not run a robust number of cost sensitivities and only look at a selective list of cost sensitivities if costs are found to “drive” certain scenarios.

• Storage optimization: Hybrid storage configurations and modeling will not be considered here, as NREL discussed how insights on co-location can be deduced from the modeling results of each resource separately – i.e., since storage can be located anywhere, significant results for solar and storage may suggest that LADWP could pursue solar-paired-storage resources in procurement. In addition, NREL explained that it uses a heuristic modeling approach across representative days to conduct inter-day storage optimization.

• Bottom-up load modeling: NREL will use its ResStock and ComStock model that looks at residential and commercial building load characteristics that reflects census data, electricity and fuel costs, and weather conditions, but does not include solar PV, EV charging, DR, or industry and special loads. Detailed sub-hourly energy simulations with reference, moderate, high, and stress projections will be created. The outcomes are independent of market context and policy implementation (e.g., prices, incentives). For all but one LA100 scenario (i.e., “High Load Stress” scenario), the three dimensions of EE, DR, and electrification vary together.

Although the cost implications of sourcing everything locally, electrifying all end uses, or meeting second-by-second load with renewables (i.e., no RECs) under a 100% scenario will likely be high, this approach to the city’s energy goals will create a substantial need for energy storage resources and EVs. In addition, it is noteworthy that NREL’s RPM model is capable of multi-day optimization, though it is yet unclear on how it actually works.

Common sources of criticism of NREL’s modeling approach was the use of representative days informed by historical weather data, similar to what is done in RESOLVE, which serves to reduce modeling intensity and run times, but also serves to overlook extreme weather impacts (e.g., 1-in-10 heat storms), which many stakeholders highlighted as the new normal. Others focused on the potential impact of de-energization by SCE and how it would impact the resource mix, but CESA believes those issues are likely out of scope of this type of system planning effort, though some of it could be assessed through contingency modeling. CESA’s broader concern is around the lack of transparency into the technical modeling documentation and inputs/assumptions documentation, where stakeholders like us could vet and provide feedback. NREL said this will be shared at some later time.

On June 25, 2019, a Q&A webinar was held to follow up on conversations from the in-person meeting. Specifically, there were a few key areas of discussion:

• Using OTC study input data: Like the OTC study, transmission will be modeled as an alternative to repowering.

• Energy storage inputs: NREL discussed how it will focus on lithium-ion battery storage with four-hour durations since this technology has the most robust cost forecasts. Longer-duration storage technologies do not have good estimates on cost trajectories, so they are not included in their ATB reports. The inputs and assumptions documentation may include details on how they will model other technologies such as flow batteries, CAES, and PHS.

• Modeling interim study years: Given the amount of modeling needed, there will only be some output data for interim study years. However, the more intense production cost modeling and power flow modeling will be focused on the 2030 and 2045 study years.

On August 29, 2019, NREL released a new LA100 assumptions document on that finalized the study scenarios (see below) without much change from the June 2019 meeting.

The document also detailed NREL’s capacity expansion model (RPM), which simulates hourly dispatch for five representative days every year using clustering approaches to capture operational behaviors on days where there is low output from variable generation. Subsequent production cost modeling will capture 8,760 hours and conduct sub-hourly optimization. These days represent the low, mid, high and peak load conditions throughout the year and RPM is run for each year in five-year increments until 2045 to ensure energy, capacity, and reserve requirements are met with LADWP-owned or -contracted assets. However, it appears that sub-hourly or inter-day optimization is not possible with the RPM model, which could undervalue the need for short- and long-duration storage and increase the potential for overgeneration. Furthermore, by making investment decisions in five-year increments, investment decisions may not be optimized over time. CESA highlights some of the key assumptions below:

• Climate change impacts: In response to feedback from the June 2019 Advisory Group meeting, NREL will capture climate change impacts through expected changes to air conditioning demand from a hotter climate. The team will rerun residential and commercial buildings modeling with climate-adjusted temperatures.

• Load transportation: For transportation, EV charging profiles and characteristics of charging are based on future trajectories of electrification of light-duty vehicles and buses, where all scenarios assume 100% bus electrification by 2030, which is particularly aggressive but in line with the city’s goals. The study does consider variations on charging availability at home and workplaces and allows flexible charging as a source of demand response (i.e., V1G) to better align charging with renewable energy supply. However, NREL will not consider changes in driving patterns due to autonomous vehicles, car or ride sharing, or use of public transit or consider vehicle-to-grid integration for discharge (i.e., V2G) – key areas that may not accurately reflect the potential cost impact or elasticity of electrification.

• Demand response model: The assumptions document lacks information on these assumptions. It will be important to highlight the role of BTM energy storage and EVs as DR resources.

• Distribution analysis: NREL will analyze the collection of changes needed on the LADWP distribution system to accommodate growing load and DERs, with the goal of analyzing around 75% of the distribution system under nominal operating configurations and current buildout (i.e., no new distribution infrastructure except to accommodate new resource interconnections and EV chargers) for 2030 and 2045, with extrapolation to the remainder of the system. Inverter-based resources are assumed to provide autonomous controls (e.g., Volt/VAR) consistent with interconnection requirements. The impact to the distribution grid of BTM storage is based on value to the customer. Distribution-connected larger storage systems are assumed to be dispatched as indicated by bulk system simulations (RPM and/or PLEXOS).

• Distributed generation adoption: The forecasts only focus on rooftop solar adoption but does not account for solar-plus-storage adoption. NREL’s dGen model assesses different scenarios for rooftop solar adoption based on building codes as well as bill savings under different regimes (wholesale compensation, net billing, retail compensation).

• Hybrid resources: Solar-plus-storage resources will be modeled in the production cost modeling, differentiated as DC-coupled devices where output cannot exceed the inverter rating and AC-coupled devices that are modeled as independent of each other.

On September 19, 2019, an advisory group meeting was held where NREL shared their preliminary findings on the technical and economic potential of rooftop PV, local solar, virtual net metering for multi-family buildings, and distributed storage. The study also involves broader analysis beyond typical IRP processes, including an assessment of jobs, economics, air quality, public health, and environmental justice impacts.

CESA conveyed our concern with the modeling effort trying to do too much, which can come at the expense of running additional sensitivities and requiring significant modeling run time. We detailed specific areas of feedback and offered some key areas of recommendation for consideration by the NREL modeling team and LADWP staff, as follows:

• CESA generally supported NREL’s approach to leveraging the EVI-Pro methodology to estimate EV charging infrastructure requirements by location but recommended consideration of how EV loads can be aggregated and optimized in capacity expansion modeling using Resource Planning Model (RPM), which can inform future rate design aligned with grid needs.

• CESA found the lack of assumptions developed for demand response to be a critical gap in the current modeling efforts but recommended that the NREL modeling team assess the methodology and models used by the Lawrence Berkeley National Laboratory (LBNL) to support DR adoption propensity scores and in building DR supply curves.

• CESA sought further clarification on whether renewable resources can be modeled in hybrid resource configurations.

• A potential concern and limitation of the distribution analysis was that the impact of distributed PV generation on upgrade costs may be overstated without the incorporation of paired BTM storage in DPV forecasts conducted by dGen.

• NREL should consider modeling consecutive days for each of the years considered in the bulk system capacity expansion modeling to capture weekly and seasonal storage effects.

• CESA was supportive of including conventional plant retirement using annual capacity factor as proxies but these factors should be substantiated, or alternatively, an economic retirement module in the RPM optimization logic should be built into the model.

• The energy storage cost data using NREL's Annual Technology Baseline reports were reasonable, but the focus on four-hour lithium-ion batteries only overlooked the broad range of storage technologies that can be best addressed by modeling additional candidate resources.

• CESA recommended that NREL model BTM storage as a discrete resource that can be optimized in capacity expansion modeling.

See CESA’s informal comments submitted on November 4, 2019 on the draft assumptions document

On November 25, 2019, NREL published its revised study assumptions. Some of the major revisions include:

• Demand response: Program sizes and capabilities are assumed for each scenario and model year based on the 2030 goals identified in LADWP’s DR 2014 Strategic Implementation Plan, including 215 MW of C&I load and 500 MW of DR overall, which are assumed to enable 48 hours of interruptible load per customer per year, up to 4 hours per day. Bring-your-own-device (BYOD) programs are also assumed for heating and cooling devices, starting in 2020. Importantly, DR is eligible to be selected endogenously and with optimized dispatch in the RPM model at very high-priced periods (e.g., $10,000/MWh strike price), but they will not be included in distribution planning models.

• EV charging: Within the DR assumptions, light-duty EVs are assumed to be able to have delayed charge scheduling. Participation rates start at 4-5% in 2020 and increase to 8-32% by 2030, after which they are held constant. Due to higher power capacity, L2 participation is assumed to be incented at higher levels to provide these load shifting capabilities.

• Climate change impacts: To reflect these impacts, air conditioning demand based on higher daily maximum temperatures. This change was noticed earlier but was memorialized in the revised assumptions. Other climate-related impacts is unable to be modeled at this time given the scope and timeframe of the study.

• Water usage: Water conservation assumptions for industrial loads are aligned with the aggressive assumptions in LADWP’s 2015 Urban Water Management Plan, with local supply assumptions for the moderate and high load projections.

On December 5, 2019, an advisory group meeting was held where NREL shared some preliminary bulk system modeling results, which showed significant amount of renewable resources (1.3 GW and 3.4 GW of wind, and 3.4 GW and 3.6 GW of solar in 2030 and 2045, respectively) built outside of the basin across all scenarios, thus requiring significant amounts of both standalone and paired storage and transmission buildout. The investments through 2045 were estimated at $36 billion. Notably, the reference case, which includes OTC repowering, was returned to the modeling runs to reflect LADWP-approved projects for transparency and comparability purposes (through 2036), though this case will not serve as the basis for LA100 scenarios since the LA Mayor has already ruled against repowering these plants.

With this resource buildout in the SB 100 scenario, the modeling results showed high rates of economic curtailment, with higher levels of solar overbuild and economic curtailment if no gas or biofuels are allowed in the other scenarios. As a result, capacity that does not rely on variable resources were found to become increasingly valuable in the absence of RECs and gas generation to meet LA’s 100% renewable goals. However, no resource adequacy issues were found in the initial modeling results that looked at a single weather year and at short-duration outages of generation and transmission, though in-basin gas generation was relied upon heavily during periods of low solar irradiance.

Storage was found to play a critical role in shifting variable generation diurnally (i.e., from day to night), especially as it was more cost-effective to build low-cost solar and wind resources along with significant amounts of storage as opposed to building alternative renewable resources (e.g., biofuel plants). Existing PHS and CAES was also found to be utilized significantly on peak demand and low-load days (e.g., spring), especially in the LA Leads scenario where only emissions-free resources could be used (i.e., no biomass or gas).

Notably, concentrated solar power (CSP) with thermal storage was used as a proxy for long-duration storage resources (greater than 8 hours), which were found to be valuable in deep decarbonization scenarios, with over 3.5 GW added by 2045; NREL noted that it will include separate candidate resources representing such long duration capabilities and predicted that such resources may be needed at higher levels when the modeling assesses transmission outage sensitivities. There were no challenges or issues found with RA and reliability in their production cost modeling of the selected portfolios.

NREL caveated its preliminary results as only including electricity demand projects completed in January 2019 and not yet incorporating assumptions from the LA Green New Deal, which includes more aggressive assumptions for electric bus adoption and demand response in addition to climate adjustments for building loads. Furthermore, while customer projections for rooftop solar were included, with the moderate case being not too different from historical trends, NREL shared that it has not yet included local ground-mounted and carport solar and local storage. Finally, NREL noted that the bulk system modeling only looked at short-duration outages and a single weather year, whereas for the final run, it will look at longer-duration outage with a look at specific limits on transmission upgrades and multiple weather years. The final run will also update cost and performance assumptions, conduct power flow and investment cost analyses, and conduct sub-hourly simulations for renewable resources (beyond just the hourly simulations conducted in the preliminary run).   

In the distribution analysis of the 4.8-kV distribution system, NREL conducted “snapshot” analysis on all feeders and “dynamic” analysis of hosting capacity on select feeders as well as power flow analyses for transformer/line overloads and voltage violations. As a result, NREL found that 86% of LADWP’s feeders in 2045 were “okay” and did not require upgrades with new loads under moderate scenarios (i.e., 2.1 GW rooftop solar, moderate efficiency and EV adoption), assuming routine maintenance and smart inverter requirements. Rooftop solar was found to decrease violations for 18% and increase violations for 14% of distribution circuits and feeders assessed and to create some transformer violations on low load days. The impact of local storage, high EV loads, and the 34.7-kV distribution system has yet to be assessed, and NREL clarified that the dGen model does not incorporate upgrade costs as part of its assumptions for solar uptake.

Finally, in the initial results related to air quality impacts and environmental justice, NREL presented on how the dGen model selected 39% of rooftop solar to be located in CalEnviroScreen-defined disadvantaged communities (DACs) – lower than the 50% of LADWP’s population and slightly lower than the 42% of the technical potential that is located in DACs. The modeling team only shared progress updates on ongoing air quality and GHG emissions lifecycle analysis without any initial data.

The initial LA100 modeling results were promising and improving as they consider an expanded scope of candidate resource technologies and encompass a broader range of perspectives for long-term planning that looks at not only capacity expansion but also production cost, power flows, and distribution analysis. Overall, storage was showing up well in the initial modeling results in the deep decarbonization scenarios, where storage may be selected in greater amounts with higher load electrification, consideration of in-basin constraints, and potential to rely on emissions-free resources only. CESA provided some informal feedback to the NREL and LADWP team on the following points:

• Since EVI-Pro is a cost-minimization model that may overlook the potential to develop grid-responsive higher-capacity chargers, NREL should incorporate smart EV charging in the demand response (DR) assumptions to demonstrate this additional value add.

• DR assumptions are a welcome addition to the LA100 modeling efforts but they should differentiate use limitations and economic dispatch based on technology-specific capabilities and costs.

• Distribution analysis results will be more informative when BTM storage is incorporated and upgrade deferral value is optimized.

• Multi-day and seasonal storage optimization and storage cost technology assumptions should be provided to help us provide more detailed feedback.

• Distributed generation adoption modeling should incorporate available storage-related incentives but BTM storage should also be included in the bulk capacity expansion modeling.

• Production cost and power flow modeling of the LA Leads scenario will inform no-regrets investments, such as for longer-duration storage systems.

See CESA’s informal comments on March 11, 2020 on the LA100 Revised Assumptions Document

On May 19, 2020, LADWP published a revised assumptions document, which included several changes. Overall, the changes were incrementally promising, and the modeling process has turned out to be comparatively nimble to capture distribution benefits, apply heuristic constraints for inter-day storage capabilities, assess bulk resiliency needs of vulnerable transmission corridors, add new candidate resources (i.e., hybrids, compressed air energy storage), and approximate a “generic” long-duration resource. Specifically, the key changes include the following:

• EV and transportation load: NREL confirmed that the charging infrastructure buildout is not optimized and instead sized to ensure driving needs are met. The scenarios were constructed by assuming different amounts of residential and workplace charging availability, using an even split of L1 and L2 chargers per previous surveys and analysis. NREL then estimated the amount of public L2 charging and DCFC needed to guarantee that trips could be completed. Optimizing the charging infrastructure to account for broader distribution and bulk benefits would add a significant increase in modeling iterations and costs. The DR from EVs comes in the form of load shifting within one day (e.g., from evening to later at night for most residential charging, which will be updated in its revised Assumptions Document to reflect these details. While the dGen modeling of PV and storage reflects the increased load from EV charging, it does not reflect the load adjustments from shifted EV charging.

• Demand response (DR): NREL included more details on the technical capabilities of the modeled DR resources. Most of the DR is shiftable load (i.e., EV charging, end uses, and water system scheduling) that is able to take advantage of modest price differences throughout the day. There is then a quantity of interruptible load subject to the constraint of 48 hours per year and four hours per day. Only after those resources are exhausted, NREL’s models consider adding a $10,000/MWh strike price. While NREL is not considering storage explicitly for DR, customer-sited storage is being added to most customers with rooftop solar, with their dispatch modeled based on value to the grid and through the retail tariff structure. Multiple-use benefits are not being assumed explicitly, including for EV charging infrastructure, but the distribution modeling does evaluate upgrade needs separately, thus uncovering some distribution value (i.e., almost akin to a non-wires alternative). Time-series distribution analysis for the circuits with the highest penetration of EV charging considering shifted (with DR) and unshifted profiles will also be conducted.

• Distribution analysis: NREL made some updates to their modeling to change the way BTM storage is dispatched to align more with the value to the bulk grid via RPM and PLEXOS and to the distribution modeling to capture non-wires alternative potential from combined PV and storage. The projected upgrade costs were developed in consultation with LADWP, with one of the primary triggers for protection upgrades occurring due to reverse power flows at the substation. Furthermore, the distribution analysis helps the construction of cost curves for RPM-sited solar (i.e., three cost blocks per node and used as input in RPM), which includes loads and dGen solar as the starting point and then sequentially adds the GIS-determined solar and storage locations. Resiliency is outside the scope of this modeling work, although from a bulk perspective, NREL is looking at the value of in-basin storage and other resources by modeling long-duration outages. Nothing additional will be run for resiliency needs at the distribution level.

• Bulk system capacity expansion modeling: RPM has been revised to capture hourly chronological dispatch for five representative days, no longer four, in order to include one day reflecting low variable generation availability. The representative days thus capture: low-, mid-, and high-load days; the peak day; and low variable resource renewable generation days. The energy value of storage is captured by allowing intra-day energy shifting as well as heuristically constrained inter-day energy shifting. The capacity value of storage is captured through algorithms that leverage chronological 8,760 load and variable generation time-series to evaluate the ability of storage (specific to the duration of each technology) to reduce peak constrained by the ability to charge, inverter capacity, and efficiency.

• Candidate resources: NREL recognized the wide-ranging number of technologies that could provide multi-day to seasonal energy shifting, including hydrogen storage. Due to the uncertainty of future cost and performance and the lack of maturity of these technologies, NREL explained that it will not represent specific technologies but instead characterize “long-duration storage” options generally as a relatively high-cost, low-efficiency storage option, assuming a 45% roundtrip efficiency and capital costs that start at $6,500/kW in 2025 and declines to $2,000/kW in 2045. This will be further examined in future meetings and a write-up on candidate technologies will be included in the final report.

• Distributed generation adoption: NREL explained that the net billing (moderate growth) and net metering (high growth) tariffs provide a rationale to underpin two different growth projections for customer-owned solar, not to evaluate the cost-benefits of those tariffs. Since net metering does not communicate some of the economic signals that could incentivize storage, NREL explained that the BTM storage optimization from the bulk-grid perspective will in effect provide the incentives for BTM storage adoption.

• Production cost modeling (PCM) and power flow analysis: NREL explained that their models have the capability to incorporate primary frequency response (PFR) as an explicit constraint. However, LADWP’s PFR requirement is small, estimated around 70 MW based on 25 MW/0.1 HZ with a maximum delta frequency of 0.28 Hz. Furthermore, unlike regulating reserves, the PFR is based on the interconnection-wide requirements of the single largest contingency, which will not increase with renewable penetration. Therefore, NREL reasoned that its modeling of a generic “spinning” reserve product can respond to LADWP’s local contingency events and should be more than sufficient to provide their likely small PFR obligation.

On July 9, 2020, NREL shared more insights on how they will model Renewable Combustion Turbines (RE-CT), which are a combustion turbine is coupled with market-purchased renewable fuel (e.g., biogas, biofuel, hydrogen, RE-ammonia, RE-methane). Unless otherwise specified, it is assumed to use either biogas or synthetic gas prior to 2045; in 2045, it is assumed to convert to H2. Gas fuels will be provided through a pipeline while liquid fuels will be provided through rail with local storage. In addition, a Hydrogen Combustion Turbine (H2-CT) and fuel cells will also be modeled that assumes fueling with self-produced hydrogen with an electrolyzer. Both dedicated hydrogen technologies are treated similar to a battery, with increase in generation to produce the fuel, to be stored for later use. Wind and solar are crucial sources of energy across all scenarios. Finally, NREL sought some feedback on how they should model flexible AC transmission and DR to address the cloudy-day issue. In general, the draft results under these scenarios show trade-offs between transmission investments to support greater out-of-basin resource buildout versus renewable combustion and hydrogen fuel cells.

Overall, CESA was supportive of the LA100 modeling efforts. CESA supported the additional biofuels and hydrogen storage options related to 90% to 100% clean energy challenges but recommended that the modeling also more robustly consider transmission investments to meet in-basin needs and constraints. Multi-day and seasonal storage optimization and long-duration storage technology assumptions should be detailed in the Assumptions Document. In addition, the customer-only perspective and lack of consideration of curtailment impacts on solar adoption may overlook certain customer investment decisions. Linear assumptions for customer-sited storage attachments to solar are overly conservative and forecasts for standalone storage deployments should be included. Finally, CESA recommended that NREL reconsider the inclusion of electric bus charging profiles in the min-delay and max-delay given their potential to provide load shifting capability, and was supportive of the DR assumptions and clarifications and the assessment of long-duration outages for the 2045 context.

See CESA’s informal comments on July 29, 2020 on the Preliminary Modeling Results

On July 16, 2020, NREL presented some initial economic and workforce impact study results. In collaboration with USC and CSU, the team used the Computable General Equilibrium (CGE) and the NREL Jobs and Economic Development Impacts (JEDI) suite of input-output models to produce the onsite and supply-chain economic impacts analysis, though it does not capture induced impacts. CGE and JEDI used many of the same structures and assumptions, though the former aggregates results and looks at net impacts (e.g., accounting for ratepayer costs for investments) whereas the latter separates results and only looks at gross (positive) impacts. Annual construction and installation jobs are primarily driven by solar and storage. The numbers will be updated to the final capacity expansion model results.

On July 23, 2020, NREL presented its methodology and preliminary results on air quality impacts in addition to resulting morbidity and health effects from exposure to particulate matter and ozone. NREL explained that it constructed a model-ready emissions inventory from source-oriented raw emissions for “current” time and created an emissions inventories that project air pollutant emissions under selected LA100 scenarios for 2045 (i.e., greater electrification and removal of gas power plants), where the emissions factor is multiplied by the “activity” associated (e.g., generation, transportation, building load).

On July 30, 2020, NREL shared the preliminary results on 2030 and 2045 distribution costs and impacts of changes to load, rooftop solar, and storage to required infrastructure, finding that estimated capital cost of distribution system upgrades needed for changes associated with 100% renewable electricity pathways from 2020 to 2045 ranges from $190 million to $460 million depending on the scenario. Between 68% to 86% of the costs are on the 4.8k-V system, depending on the scenario. While still assessing the results, LADWP argued that upgrading the distribution system today can resolve existing issues and decrease the cost of integrating new loads and distributed solar/storage, though these costs are lower than what they spend annually today (e.g., does not include existing distribution issues or routine O&M costs). These distribution costs are fed back into the capacity expansion model. Notably, NREL hypothesized that load and customer-adopted solar is more spatially widespread, and so it is more likely that the upgrades made to integrate those resources benefit local solar than vice-versa. Energy storage, properly dispatched, can align profiles and increase hosting capacity. Certain key locations were also identified for local solar potential.

Once-Through-Cooling (OTC) Repowering Study

Background

On June 6, 2017, LADWP announced that all planned in-basin repowering projects will be put on hold until a system-wide independent analysis is completed on whether non-emitting alternatives could replace repowering plans.

Study Results

On June 7, 2018, Worley Parsons presented an update on a OTC study at the Advisory Group meeting where 126 combinations of retirement scenarios and replacement plans are evaluated through a “tiered analysis” where solution options are disqualified based on technical feasibility and whether RA capacity is maintained. The initial study results are showing that it may be doable to forego repowering all of LADWP’s coastal and aging fossil generation plants. LADWP is thus actively considering downsizing

On August 16, 2018, Worley Parsons presented an update on an OTC study at the Advisory Group meeting where 126 combinations of retirement scenarios and replacement plans are evaluated through a “tiered analysis” where solution options are disqualified based on technical feasibility and whether RA capacity is maintained. The initial study results are showing that it may be doable to forego repowering all of LADWP’s coastal and aging fossil generation plants. LADWP is thus actively considering downsizing.

On November 27, 2018, Worley Parsons presented their system analysis of system reliability through 2036 and evaluation of alternatives (e.g., utility-scale renewables, four-hour battery storage, DERs, transmission upgrades) to LADWP’s 2016 IRP OTC repowering plan. The consultant team looked at scenarios for different combinations of OTC unit retirements and repowerings.

The study methodology established different criteria and constraints by which to assess the viability of alternatives:

• Resource adequacy: Is there enough generation to keep the lights on?

• Technical feasibility: Are there adequate resources and space for development?

• Transmission reliability: Is there enough capacity in the wires to transmit the power?

• System simulation: What are the GHG and natural gas reductions and total costs?

• Operability analysis: Can we reliably operate the system given the forecast uncertainty and intermittency of renewables?

• Implementation: Can we build projects and implement programs in time?

• Metric outputs: How do the cases rate in terms of development risk, organizational risk (e.g., portfolio management), total costs, and environmental impact?

The below portfolios were developed as alternatives to each of the repowering cases based on all of the study criteria above. In assessing the implementation risk analysis, the consultants examined energy storage related challenges, including limited space at LADWP sites that might impact site acquisition costs as well as broader challenges around fire safety, permitting, and end-of-life disposal.

Based on this analysis, the consultants generally found that solar or wind alone does not satisfy the resource adequacy objectives, energy storage must be paired with renewables to minimize GHG emissions and achieve lower investment costs, and the number of transmission upgrades increase with higher levels of non-emitting alternatives. Importantly, the study found that the elimination of more gas repowering projects had the effect of increasing the utilization of other non-OTC gas units.

Thus, given these tradeoffs, the consultants recommended “Case VI” that would eliminate two of the three re-powering projects at Haynes and repower Scattergood Units 1 and 2 and Harbor Units 1 and 2. The alternative portfolio would include 520 MW of energy storage by 2027 and 2030 along with 300 MW of in-basin solar by 2025 and 2030, 161 MW of wind, and 161 MW of demand response resources by 2025. Specifically, elimination of the Haynes repowering project produced relatively high levels of environmental benefit, would not require transmission upgrades, and has the space to support up to 800 MW of energy storage projects. The costs were also only moderately higher (8%) than the IRP and would require a bit more energy storage than planned for in their IRP (404 MW). By comparison, complete repowering would have required significantly higher costs relative to the IRP (26%). There were some specific challenges identified as well for the Harbor repowering project serving critical locations (e.g., LAX expansion), requiring major transmission upgrades, and having higher development costs and limited space. The Scattergood repowering project was also identified as having the highest risk due to the more near-term OTC compliance year of 2025.

On February 11, 2019, Los Angeles Mayor Eric Garcetti announced his decision to abandon LADWP’s repowering plans for the Scattergood, Harbor, and Haynes natural gas power plants. The city is under state orders to shutter 10 gas-fired generating units at those facilities in the coming years because they use ocean water for cooling (i.e., once-through-cooling facilities).

SB 801 Energy Storage Study

Background

SB 801 was passed in 2018 that required LADWP to coordinate with the LA City Council to determine the cost-effectiveness and feasibility of deploying a minimum aggregate total of 100 MW of cost-effective energy storage in a study to be completed by June 1, 2018.

Study Results

On August 3, 2018, CESA received LADWP’s SB 801 Study on the cost-effectiveness of energy storage, even though the study was completed internally in April 2018.

Using EPRI’s StorageVET modeling tool and assumptions from LADWP, EPRI concluded that a 200 MW solar and 100 MW (400 MWh) battery energy storage system (BESS) project would be cost-effective (i.e., benefit-to-cost ratio greater than one) from 2022 and beyond. EPRI conducted the analysis for the combined resource under four cases representing different operational profiles (e.g., charging restrictions from grid) and revenue streams (e.g., spinning reserve, capacity, frequency response), which resulted in project benefits ranging between $25 million and $30 million per year across a 20-year power purchase agreement (PPA). EPRI identified four cases:

• Case #1: The storage system could charge from the grid to provide energy arbitrage and can commit to full 200 MW of spin reserves. The system would perform 289 effective cycles.

• Case #2: The storage system could charge from the grid to provide energy arbitrage and can commit to full 185 MW of spin reserves and set 15 MW for Frequency Response. The system would perform 282.4 effective cycles.

• Case #3: The storage system will charge following the PV generation pattern and can commit to full 200 MW of spin reserves. The system would perform 302.8 effective cycles.

• Case #4: The storage system will charge following the PV generation pattern and can commit to full 185 MW of spin reserves and set 15 MW for Frequency Response. The system would perform 284.2 effective cycles

Using EPRI’s results, LADWP conducted a feasibility review for the combined resource to interconnect to its transmission system, which would require some transmission upgrades that are already underway and would be completed by 2022.

Unfortunately, one downside of the study was that LADWP decided not to evaluate the cost-effectiveness of non-battery energy storage technologies. LADWP determined that:

• Pumped hydro requires lengthy permitting processes and it is usually cost-effective for larger capacity.

• Compressed air energy storage (CAES) is not widely deployed, and it would be difficult to implement due to its geographic location requirements.

• The typical scale of thermal energy storage does not exceed 1 MW.

• BTM battery storage would require years of coordination and particular operational optimization practices facilitated through the use of Distributed Energy Management Systems (DERMS).

CESA is disappointed that non-battery storage technologies were not also modeled and considered, and efforts will continue to broaden policymakers and energy storage buyers about the full range of energy storage technologies. In sum, despite that limiting aspect of the study, it looks like SB 801 will drive 100 MW of new battery storage procurement by LADWP and CESA will provide timely updates once LADWP issues the RFP. Given these study results, LADWP identified its next steps to be to further study the transmission upgrade needs (which depend on the precise location of the solar-plus-storage project) and to initiate procurement for the solar-plus-storage system in 2019.

On August 16, 2018, an Advisory Group meeting was held for NREL to present on the various steps in putting together the scenarios, modeling inputs, modeling outputs, and validation and to showcase the extensive and sophisticated tools that they will use, including capacity expansion and production cost modeling. For the carbon emissions assessment, NREL will take a lifecycle approach that will entail a literature review on the lifecycle emissions of generation sources and battery storage. NREL noted that the literature is rather thin on utility-scale batteries. For the OTC study, NREL indicated that it is approaching the final phases of the study, down to 12 potential options which will now go through “constructability” and “metrics” scores. NREL is bounding the potential energy storage options at 5,200 MW of utility-scale energy storage and 261 MW DER energy storage in the LA Basin, with “out-of-basin” solutions not being considered. The energy storage solutions will be four-hour batteries. The “constructability” assessment for battery storage will include considerations of land use, local opposition, fire risk, permits, disposal of chemicals, chemical replacement, and costs.

Disadvantaged Communities

Background

Senate Bill (SB) 350 calls upon the CPUC to help improve air quality and economic conditions in communities identified as "disadvantaged". For example, changing the way we plan the development and future operations of power plants around the state, or rethinking the location of clean energy technologies to benefit burdened communities. Additionally, SB 350 requires that the CPUC and the CEC to create a Disadvantages Communities Advisory Group, which will assist the two Commissions in understanding how energy programs impact these areas and could be improved.

Many, but not all, of the commonly used definitions of “disadvantaged communities” in California are tied to the legislative definitions that guide State Cap-and-Trade investments. Through Senate Bill (SB) 535 and Assembly Bill (AB) 1550, the California Environmental Protection Agency (CalEPA) is responsible for identifying disadvantaged communities for purposes of the Cap-and-Trade funding program. CalEPA designated as disadvantaged communities the top 25% of highest scoring census tracts using results of the California Communities Environmental Health Screening Tool (CalEnviroScreen).  CalEnviroScreen determines disadvantaged communities based on geographic, socioeconomic, public health, and environmental hazard criteria (Health and Safety Code Section 39711), with specific focus on identifying the most pollution-burdened and vulnerable communities.

In 2016, AB 1550 also created new investment requirements for disadvantaged communities and created new requirements for low-income communities and households. Health and Safety Code Chapter 369, section 39713 states: “Low-income communities” are census tracts with median household incomes at or below 80 percent of the statewide median income or with median household incomes at or below the threshold designated as low-income by the Department of Housing and Community Development’s list of state income limits adopted pursuant to Section 50093. Given the intention of the legislation – reducing greenhouse emissions – the nexus of this definition is to identify and prioritize investments for communities disproportionately affected by environmental pollution tied to GHG emission sources.

The CPUC uses the term “disadvantaged communities” in several programs and proceedings.  It is often, but not always, defined consistently with CalEPA’s definition. One example where the CPUC uses a variation of this definition is the Green Tariff program, which uses the top 20% of ranked census tracks. Another example is IOU transportation electrification programs, where the utilities can consider the 25% highest burdened census tracts on either a state-wide basis, or service-territory wide basis. Still another is San Joaquin Valley “disadvantaged communities”, which under PUC 783.5, seeks to provide affordable energy, defines disadvantaged communities as areas with: (1) at least 25% of residential households with electrical service enrolled in CARE; (2) a population greater than 100 persons within its geographic boundaries; (3) located no further than seven miles from the nearest natural gas pipeline operated by a gas corporation; and (4) located in one of the eight San Joaquin Valley Counties.

Pursuant to SB 350 (2015) and codified in Public Resources Code Section 400, the CPUC and the California Energy Commission established a “…disadvantaged community advisory group consisting of representatives from disadvantaged communities identified pursuant to Section 39711 of the Health and Safety Code. The Disadvantaged Communities Advisory Group (DAC AG) adopted an “equity framework” to guide its deliberations.  The equity framework broadens the definition of disadvantaged communities as established by Health and Safety Code Section 39711 to also include: (1) tribal lands; (2) census tracts with area median household incomes less than 80% area or state median income; and (3) households with income less than 80% of Area Median Income (AMI).

The Environmental and Social Justice (ESJ) Action Plan, which was adopted by the CPUC on February 22, 2019, references the expansive Disadvantaged Communities Advisory Group definition of “disadvantaged communities” for its definition of “Environmental and Social Justice Communities,” which would broadly apply to its authority to serve “disadvantaged” and “vulnerable” ratepayers, in all industries regulated by the CPUC, including water, telecommunications, and transportation.

En Banc Hearings

On July 6, 2017, the CPUC held an Environmental Justice and Disadvantaged Communities en banc hearing to discuss challenges and potential solutions, including how to reduce the need for polluting energy resources in disadvantaged communities and how to increase investment of clean energy resources in these communities.

On August 1, 2017, the CPUC and CEC held a joint workshop to discuss the implementation of the Low-Income Barriers Study. This report continues to be the crux of many discussions around integrating disadvantaged communities in California’s clean energy policies and programs.

On August 31, 2017, the UC Berkeley Labor Center issued a report that found that 43% of entry-level workers in renewable energy construction live in communities that are designated as "disadvantaged" by the CalEPA, a rate much higher than the 25% rate for the general population. Nearly 47% of these workers lived in communities with unemployment rates of at least 13%, showing the importance of solar development for these communities. 

Disadvantaged Communities (DAC) Working Group

The Disadvantaged Communities (DAC) Working Group aims to track all the proceedings and events that address low-income and environmental justice issues. With SB 350 setting DAC objectives for the IRP, DACs are an increasing focus across all proceedings at the CPUC.

On July 31, 2017, the CPUC issued a Joint CPUC-CEC Staff Proposal that proposes a draft DAC Advisory Group structure and framework. The DAC Advisory Group will review and provide advice on clean energy programs proposed by the CPUC and the CEC in response to the statutory requirements in SB 350 and determine whether those proposed programs will be effective and useful in DACs. The Staff Proposal lays out guiding principles to increase benefits, increase access, and maintain affordability through clean energy technologies and programs. The DAC Advisory Group will consist of 11 members, including five selections each made by the CPUC and CEC and one selection by the Governor’s Office. The formation of this group is in response to statute but also represents a commitment by the joint agencies to ensure DACs are considered in all clean energy policy and programs.

On November 1, 2017, Draft Resolution E-4893 was issued that establishes, and adopts the charter of, the Disadvantaged Communities Advisory Group, as advisory to the CPUC and the CEC on the effects of clean energy programs and air pollution reduction programs established pursuant to SB 350. Specifically, the group will tasked with considering the extent to which proposed programs:

• Increase the benefits of clean energy programs in disadvantaged communities (e.g., supporting local employment growth, reducing pollutants and health risks)

• Increase access to clean energy technologies for disadvantaged communities

• Maintain or enhance the affordability of energy service in disadvantaged communities by considering potential rate impacts of any proposed program

On December 14, 2017, Resolution E-4893 was issued that approved the establishment and charter adoption of the Disadvantaged Communities Advisory Group (DACAG).

On May 30, 2018, a joint agency workshop was held that presented a draft plan on a framework and a range of potential strategies and associated action items to address the key barriers limiting deployment of energy efficiency and clean energy resources in California’s multifamily buildings. The CEC and CPUC also solicited feedback on the Clean Energy in Low-income Multifamily Buildings (CLIMB) action plan.

On March 22, 2019, a Disadvantaged Communities Advisory Group (DACAG) meeting was held on March 22 that focused on a draft comment letter to the CPUC and CEC Commissioners to adopt the energy storage programs for affordable housing tenants and property owners for the following reasons:

• A diverse set of pilots is required in the near-term in order to equitably prepare disadvantaged communities and low-income communities for the impacts of climate change.

• The proposed energy storage programs are distinct from the SGIP Equity Budget and avoid current barriers within the SGIP program.

• Key stakeholders support the proposed energy storage programs.

• AB 2868 requires broad prioritization of low-income customers.

In addition, the DACAG reviewed a draft comment letter to the CPUC and CEC Commissioners to adopt and establish the Equity Framework as a central tenant to all policies and proceedings in addition to their definition of disadvantaged communities.

Multifamily Working Group

The Multifamily Working Group (WG) was officially formed as part of D.16-11-022 from the California Alternative Rates for Energy (CARE) and Energy Savings Assistance (ESA) proceeding (A.14-11-007). 

On July 7, 2017, the CPUC held a webinar to discuss the WG’s purpose to implement multifamily directives, evaluate program implementation progress, suggest improvements to existing/current multifamily program design and how to integrate and implement in decisions the ‘common area’ measure directive, and develop a process to gain access to program administrators (e.g., customer engagement, success using single POC model). The WG will hold ad hoc meetings every quarter to drive results. CESA will continue to monitor this WG. 

Advancing Energy Equity (19-IEPR-05)

This docket was opened by the California Energy Commission (CEC) on advancing energy equity through the state’s DER programs and policies and will focus on increasing access and ensuring equitable benefits to low-income and DAC customers.

On July 30, 2019, a workshop was held where the CEC and CARB reported on implementation progress from the recommendations of the SB 350 Barriers Study, including around convening working groups focused on energy equity issues, establishing a one-stop shop for resources, and new DER programs focused on low-income and DAC customers. Clean Energy Works presented on how DER access can be better achieved through tariff-based mechanisms where low-income and DAC customers save an ongoing basis as opposed to using on-bill loans, which may be limiting due to financing challenges. Notably, Commissioner Guzman-Aceves highlighted the need to focus on individual resiliency, including with storage, and to address overlooked situations, such as language access to DER information, and emerging situations, such as disconnections. She also observed that developers may not be pursuing the equity market for DER opportunity due to the constant state of pilots. Meanwhile, CARB Executive Director Richard Corey urged action to increase EV sales, where the state stands at only 600,000 EVs when the current market is 29 million vehicles overall.

CESA presented on a panel about DER access and discussed the barriers and potential benefits of energy storage for low-income and DAC customers. CESA recommended greater consideration of energy storage for resiliency, the importance of leveraging synergies with other low-income DER programs, and the need to think creatively on how energy storage in DACs can be used for grid services.

See CESA’s comments on August 13, 2019 on the Equity Workshop

Demand Response (DR) Pilots

Background

On February 8, 2019, the IOUs submitted advice letters on their plans for disadvantaged community (DAC) pilots. Pursuant to D.18-11-029, the proposed pilot shall include:

• Target DAC location

• Strategy to target residential and small commercial DAC customers

• Amount and form of economic benefit for participating customer and third party

• If and how the proposed pilot will be bid into the CAISO market

• Theory, goal, and purpose of the pilot intervention

• How the IOUs are coordinating with the DAC Advisory Group

• If and how the IOUs are coordinating with each other

• How to track cost-effectiveness for the purpose of informing future programs

• Justification for choice of a third party or utility

• Customer protection measures that will be taken

PG&E

PG&E submitted a plan to partner with Olivine to leverage and expand on the Richmond Community Energy Initiative (CEI) and to study the willingness and ability of residential customers to provide DR in DACs within 10 miles of the Malaga Power Generation facility in the City of Fresno. This $1-million pilot will involve 2,500 residential in a summer-peaking inland climate zone where behavioral and automated DR load reduction and load shifting will be integrated in the CAISO market. The effectiveness of varying triggers such as grid need, pricing, and air quality will be tested, targeting high-value times when the Malaga power station may be dispatched. Up to 10 DR events will be targeted for each study season and incentives will be paid as upfront incentives ($250) and for both specific events as well as consistent performance and participation in surveys. Participants will also receive free technology installations. PG&E will avoid calling DR events that may lead to customers incurring higher energy costs and will focus on community engagement through local community organizations.

On June 24, 2020, PG&E submitted an advice letter detailing the implementation delays required due to the COVID pandemic, which has created a need to extend the open enrollment, surveys, and first incentives payout to be delayed from June 2020 to at least September 2020. As a result, pilot report and analysis will be shifted by two quarters from Q4 2021 to Q2 2022. The pilot was originally authorized in D.17-12-003 for a three-year, $1-million pilot program targeting DR in constrained local capacity areas and DACs. The fallout of the COVID-19 pandemic has reverberated across many customer programs, including this one. With customer programs, particularly pilots, potentially facing funding and customer acquisition challenges, delays to implementation should be expected. PAO submitted a protest on the various budget category renaming and the modifications to budget levels (e.g., 34% increase in administration), arguing that the justifications for these modifications are not substantiated.. PG&E, however, responded that the CPUC afforded PG&E with some flexibility to reallocate budgets as needed

SCE

SCE proposed a $1-million pilot that would install grid-responsive control devices on heat pump water heaters (HPWHs) to eligible residential customers on CARE rates but who lack access to natural gas service in the communities of California City, Ducor, and West Goshen. Participating customers would receive a $175 annual bill credit in exchange for allowing SCE to manage their HPWH operations during DR events, which could occur at any time of the year, and may last up to 6 hours per day, up to 35 hours annually. The event triggers will be mirrored after those of SCE’s Summer Discount Plan (see Section 7):

• CAISO Warning, Stage 1, Stage 2, Stage 3, or Transmission Emergency

• Constrained electric grids (as determined by SCE’s grid control center)

• High wholesale energy prices at discretion of SCE)

• Part of testing

Although participating customers cannot override individual events while participating, they may disenroll from the pilot program at any time and forfeit their bill credit. The HPWHs would be used for traditional DR load shedding and does not test for load shifting from times of high or surplus solar generation to peak demand times, nor does it plan to bid these DR resources into the CAISO market. Due to the lack of historical data, capacity payments will not be used at this time, but gathered data may be used to determine capacity payments in the future.

SCE’s DR DAC pilot will leverage SCE’s San Joaquin Valley (SJV) Pilot approved in D.18-12-015. SCE’s SJV Pilot will provide 449 qualified participants in California City, Ducor, and West Goshen the opportunity to replace their propane or wood burning appliances with up to four electric appliances including heat pump heating and cooling systems, HPWH, cooktops/ovens and clothes dryers. SCE will be testing 12 controls/communications technologies, including the grid-responsive control device, through its grid responsive heat pump water heater study which is funded by SCE’s Emerging Markets and Technologies program. SCE will install an additional 138 controls on customer’s HPWH for use in that pilot. The SCE Grid Responsive HPWH Study intends to examine the capabilities of the current HPWH technologies to “load up” or pre-heat water to allow for shifting strategies to take advantage of retail price designs. Pilot implementation will begin in 2019 and will be open to participation in 2020-2021.

On August 16, 2019, SCE submitted a supplemental advice letter that provided additional information on how its DR DAC Pilot relates to its recently approved San Joaquin Valley (SJV) Pilot. Specifically, SCE will offer to install grid-responsive control devices on HPWH offered to eligible customers by SCE’s SJV Pilot. SCE’s DR DAC Pilot will target 299 of the 449 customers who received HPWHs from the SJV Pilot. Since California City, Ducor, and West Goshen are all located in hot climate zones, CARE/FERA enrolled customers who participate in the SJV Pilot will not be defaulted to TOU rates. Since the SJV Pilot does not plan to conduct any load shed events or a load shift strategy, the DR DAC Pilot is a means to leverage concurrent evaluation, marketing, and outreach while testing a directed DR controls strategy, as opposed to a passive response via retail rates. SCE clarified that only the 299 customers with controls funded by the DR DAC pilot will be eligible to participate in the DR DAC Pilot. The 150 control devices studied by SJV Pilot will not be available to the DR DAC pilot because demand response events from the DR DAC pilot could affect the usage pattern studied by the SJV Pilot.

SDG&E

SDG&E proposed a two-part pilot. In Part A, SDG&E would identify and then target one or two small commercial facilities in National City for a BTM battery to mitigate annual energy charges as well as to maximize DR participation (e.g., capacity and energy payments). SDG&E will specifically seek to understand annualized value of dollar savings as well as the reliable DR values from discharging the battery. Due to the small amount of capacity expected for this pilot, SDG&E does not plan to integrate its pilot into the CAISO market but plans to work with third parties to implement each phase of the pilot. Part B will focus on small and medium commercial customers where SDG&E will test out different customer outreach techniques to measure DAC participation rates. Customers in National City will be targeted to enroll in existing DR programs.

On June 25, 2020, SDG&E submitted an advice letter detailing the implementation delays required due to the COVID pandemic, which has created a need to extend the outreach timeline to the end of 2021 and surveys in Q4 2020.

San Joaquin Valley (R.15-03-010)

Background

A key focus for DACs is the San Joaquin Valley rulemaking, where the CPUC aims to analyze the economic feasibility of certain energy options for DACs identified in the San Joaquin Valley. The San Joaquin Valley is known for having some of the state’s most disadvantaged communities, such that the region does not even currently have natural gas service for heat and power. Phase 2 of this proceeding will address the implementation of pilot projects that are intended to provide cleaner and more affordable energy options to 12 of the 170 DACs identified in Phase 1 of the proceeding. 

On November 8, 2019, the CPUC announced that Richard Health & Associates was awarded the contract to be the third-party administrator and implementer of the San Joaquin pilots

Track A (Data Gathering)

On February 28, 2018, each of the IOUs also submitted their proposed Data Gathering Plans to evaluate economically feasible energy options in Phase 3 of this proceeding. Comments were filed on the IOUs’ data gathering plans with the environmental justice and low-income-focused parties focused on the importance of community engagement, customer feedback, smart communication strategy (e.g., customized by language), and measurement of non-energy benefits (e.g., resilience) as part of the data gathering efforts. Others focused on the timing and process of the process and the availability of resulting data with project implementors and other parties in this proceeding.

On August 31, 2018, D.18-08-019 was issued that consolidated and approved modified versions of the IOUs’ data gathering plans to gather baseline data on energy, household, and community conditions within San Joaquin Valley disadvantaged communities. Specifically, D.18-08-019 adopted the following:

• Approved a competitive request for proposal process to select a single contractor managed by PG&E that would help ensure that work is implemented consistently across all DACs

• Directed PG&E to establish a Data Plan Working Group and to co-chair the Data Plan Working Group with ORA and Self-Help Enterprises (SHEs) that ensures a meaningful community voice

• Approved data elements and methods (e.g., mail/phone surveys, in-home/group interviews) and data gathering plan deliverables (e.g., summary statistics, aggregated and anonymized database)

• Approved the addition of eight specific communities to the list of San Joaquin Valley disadvantaged communities as well as communities partially or primarily served by municipal utilities

• Required PG&E to file a Tier 2 advice letter containing a detailed budget within 60 days of this decision

Overall, the decision found that the data gathering plan is important in contributing to the possible development of new program options for disadvantaged communities in the San Joaquin Valley and may inform modification of existing CARE and ESA programs to better serve valley residents. As compared to the PD issued on July 23, 2018, D.18-08-019 removed the $3 million budget cap and added some flexibility for PG&E to submit a larger budget proposal between $3 million and $6 million with the submission of a Tier 3 advice letter. The final decision also added a few more household data elements to be collected and expanded the eligible communities from eight to nine.

On April 3, 2019, Resolution G-3550 was issued that approved the IOUs’ data gathering plans to inform the evaluation of the approved pilot projects.

Track B (Pilot Proposals)

On January 31, 2018, the IOUs submitted pilot proposals totaling $207 million to support Phase 2 of R.15-03-010. The goal of this pilot development process is to solicit and test innovative, targeted strategies to improve access to affordable energy and improve health, safety, and air quality in the San Joaquin Valley. 

• PG&E proposed to electrify homes of customers that use propane and to install energy efficient electric appliances for free (as well as other energy efficiency and weatherization measures). All participants will receive electric supply from solar in California and receive a percentage discount on their electric bill. In addition, PG&E proposed a gas microgrid for Le Grand customers who use propane or wood. Instead, they will receive free installation new, high-efficiency gas appliances and energy efficiency and weatherization measures. This will require PG&E to build out a local gas distribution network served by a central hub near the community, including mobile tanks to supply renewable natural gas purchased by PG&E and supplied to customers at the same price as regular natural gas.
  

• SCE proposed similar electrification and energy efficiency programs to convert homes to all-electric by replacing propane and wood-burning appliances with electric versions. SCE also added a community solar pilot proposal pursuant to the NEM Decision.
  

• SoCalGas proposed almost $100 million to extend natural gas lines and retrofit homes of customers who use propane. Propane lines will be replaced with natural gas lines and propane and wood-burning appliances will be replaced with energy-efficient natural gas appliances under this proposal. Energy efficiency and weatherization measures will be a part of this proposal as well.

On March 3, 2018, several parties filed comments expressing their concerns with the IOUs’ proposed pilot projects. For example, parties have highlighted the large cost of what are supposed to be pilot projects, and the lack of ‘learning’ that could be accomplished by piloting natural gas pipeline extensions. While generally supportive of the electrification pilots and SCE’s community solar projects, the environmental and low-income parties requested that PG&E’s gas microgrid project be modified to rely on clean and renewable technologies. Among the comments, there was a decent amount of support in including energy storage solutions as part of SCE’s community solar project and other IOU proposed pilot projects in order to offset some of the effects of default TOU rates and to provide additional financial savings and reliability. Greenlining Institute called for a specific goal on energy storage, while GRID Alternatives teamed with Proteus and Tesla (Community Solar Pilot Team) to submit an alternative proposal to establish an electrification and efficiency retrofit services program to be coupled with energy storage installations. 

On March 18, 2019, the IOUs submitted a joint advice letter that attached an split incentives affidavit and agreement that was developed to strike a balance between encouraging pilot participation from landlords and protecting tenants’ rights. The affidavit and agreement included provisions to prohibit rent increases as a result of home improvements provided through the SJV pilot, and limited evictions for reasons specified – e.g., unlawful occupancy, failure to pay rent, breach of occupancy agreement, and illegal use of property. The advice letter also detailed data collection, reporting, monitoring, and enforcement approaches.

On March 30, 2018, the Community Solar Pilot Team provided their estimates of the potential costs, operational profile, and technical/contractual parameters on the energy storage aspect of their proposal in response to TURN’s data request. Serving between 180 and 240 homes, the proposal is estimated to cost $0.78M to $1.04M. Additionally, a contested pilot has been proposed by SoCalGas to extend natural gas pipelines to support the conversion of end uses to natural gas, which are being pushed back by ORA and the environmental parties. Meanwhile, the CCAs proposed that the CPUC provide implementation funds to establish a CCA in the San Joaquin Valley to achieve the objectives of this proceeding.

Comments on the proposals were submitted, with parties commenting on pilot location(s), community outreach, and cost-effectiveness, among others, when assessing the viability of different pilot concepts and implementation. ORA and TURN are concerned with ensuring that the pilots maximize learning opportunities at the least cost and avoid duplication of efforts, while other parties support more lax consideration of cost effectiveness for these pilot projects. Several parties supported the inclusion of a community solar project among the pilots, but ORA, TURN, and the IOUs cautioned about the cost shifting issue around VNEM in general. Greenlining pointed to the need to integrate the proposed DAC-SASH, DAC-GT, and Community Solar Program from the NEM proceeding into the San Joaquin pilots, while GRID Alternatives believes that additional incentives or adders are needed to support a low-income-focused community solar program. Many environmental and DER parties also discussed the need to discuss alternatives to natural gas pipeline extensions. Most importantly, there seemed to be broad support (Greenlining, NRDC, Sierra Club, and GRID Alternatives) for including energy storage in these pilots, though ORA remained skeptical.

On April 24, 2018, an all-party workshop was held on April 24 to discuss which pilot proposals to prioritize and which could potentially serve as control groups. At least one party was supportive of receiving additional natural gas service (Kern Economic Development Corporation) to support economic growth of their community.

On May 15-17, 2018, three community workshops were held in the 12 identified pilot communities where different presenters introduced their pilot proposals. Listening sessions were set up to allow for residents to voice their opinions and provide feedback on the ideas for potential pilots. The communities provided feedback on current energy conditions, where many residents have to routinely purchase propane tanks to meet their energy needs due to the lack of natural gas service. Many residents indicated that they wanted basic natural gas service as a first order. At the same time, many residents expressed an interest in community solar, though they also seek to reduce their currently high (sometimes unaffordable) electricity bills.

On June 6, 2018, a Ruling was issued that directed all parties to jointly develop several work products, including a joint proposal for a framework to assess the economic feasibility of the proposed pilot projects (e.g., extending natural gas lines, clean energy options) and a workshop to discuss that proposal. The Ruling listed nine “foundational points” (also called “points of agreement”) that describe the development and application of cost effectiveness tests in this proceeding, such as the appropriate discount rate. Parties generally agreed that bill savings and costs to participants, public and community benefits, and costs to ratepayers should be the primary considerations. However, the area where the Ruling seeks consensus on whether and how to quantitatively assess the GHG and air pollutant benefits of options. The Ruling also proposed pilot selection criteria around community support benefits, economic feasibility to participating households and ratepayers, and pilot replicability and value.

On July 18, 2018, the final draft of the joint proposal was circulated, but parties have indicated that consensus was not reached. A workshop was held on July 23-24, 2018 to discuss the proposals for the economic feasibility standard and selection criteria around community support and benefits, affordability, and replicability. Electric and gas extension rules were reviewed in terms of how project costs are socialized and how project implementation is done through partnerships with other IOUs. ORA presented on their proposal for conducting the cost-effectiveness analysis based on participant and ratepayer impacts and for limiting the budget to $30 million to $40 million for the pilot phase. Finally, TURN presented on their heat pump water heater pilot proposal – a retrofit program to replace propane water heaters for 600 households with more efficient and potentially DR-dispatchable heat pump water heaters.

On August 31, 2018, D.18-08-019 was issued that consolidated and approved modified versions of the IOUs’ data gathering plans to gather baseline data on energy, household, and community conditions within San Joaquin Valley disadvantaged communities. Specifically, D.18-08-019 adopted the following:

• Approved a competitive request for proposal process to select a single contractor managed by PG&E that would help ensure that work is implemented consistently across all DACs

• Directed PG&E to establish a Data Plan Working Group and to co-chair the Data Plan Working Group with ORA and Self-Help Enterprises (SHEs) that ensures a meaningful community voice

• Approved data elements and methods (e.g., mail/phone surveys, in-home/group interviews) and data gathering plan deliverables (e.g., summary statistics, aggregated and anonymized database)

• Approved the addition of eight specific communities to the list of San Joaquin Valley disadvantaged communities as well as communities partially or primarily served by municipal utilities

• Required PG&E to file a Tier 2 advice letter containing a detailed budget within 60 days of this decision

Overall, the decision found that the data gathering plan is important in contributing to the possible development of new program options for disadvantaged communities in the San Joaquin Valley and may inform modification of existing CARE and ESA programs to better serve valley residents. As compared to the PD issued on July 23, 2018, D.18-08-019 removed the $3 million budget cap and added some flexibility for PG&E to submit a larger budget proposal between $3 million and $6 million with the submission of a Tier 3 advice letter. The final decision also added a few more household data elements to be collected and expanded the eligible communities from eight to nine.

On September 10, 2018, parties filed their extensive responses. In particular, GRID Alternatives, Proteus, and Tesla (“CEP Team”) submitted a revised pilot project proposal that differentiates the approach to home electrification by income status and fuel-switching need that provides tiered electrification packages in accordance with customer preferences. Additionally, instead of a VNEM tariff program, the CEP Team revised its community solar proposal to align with the Community Solar Green Tariff (CS-GT) Program recently adopted in the NEM proceeding. Energy storage appears to remain a major part of these proposals. Another key storage-related pilot proposal is PG&E’s heat pump water heater (HPWH) pilot in San Joaquin Valley, which PG&E clarified may be a subset of its AB 2868 Storage Program that is pending approval. Many environmental parties continue to strongly oppose gas financing options and gas extension proposals from the IOUs. SCE also submitted a revised all-electric conversion pilot for customers who do not have access to natural gas, which will include weatherization services, enrollment in bill-reducing programs, participation in community solar, and education on SGIP funds. SCE indicated that it may look to partner with a battery storage company and a community solar anchor tenant perhaps through the new DAC Community Solar Program to study the grid benefits of a combined solar and battery storage pilot. Cal PA, however, expressed concerns that many of the pilot designs raise equity concerns and are not scalable beyond the pilot communities.

On October 3, 2018, a Ruling was issued that set out the CPUC’s straw proposal for pilot projects in the 12 identified DACs: Allensworth, Alpaugh, Cantua Creek, Ducor, Fairmead, Lanare, Le Grand, La Vina, Monterey Park Tract, (MPT), Seville, California City, and West Goshen. It also established the following objectives for each pilot:

• Gather inputs to assess cost-effectiveness and feasibility during Phase 3 of the proceeding

• Provide equitable access to affordable energy options in participating pilot project host communities

• Reduce household energy burden for participating pilot project host customers

• Increase health, safety and air quality of participating host pilot project communities

• Test approaches to efficiently implement programs

• Assess potential scalability

Given these objectives, the CPUC used the following principles and evaluation criteria to guide the selection and modifications of pilot proposals:

• Legislative directive of AB 2672

• Community support for projects and customer choice

• Measured transition to cleaner energy sources considering need to meet community energy needs and potential for electrical outages

• Affordability and reasonableness of costs

• Pilot replicability and value

• Pilot project as data gathering and learning, not an ongoing program

• Leverage efficiencies while maximizing third-party implementation

The CEP Team (GRID Alternatives, Tesla, & Proteus Inc) , PG&E and SCE all proposed some type of storage element as part of their pilots. The CEP Team proposed to include in-home energy storage (battery or water heating with energy storage) as an “optional” measure that participating households could select as part of their allocated home improvement subsidy. PG&E suggested it could leverage an electric hot water heater storage pilot it proposed to address AB 2868’s new storage mandates, most likely in the city of Alpaugh. SCE indicated it would actively promote both solar and storage through the DAC-SASH and SGIP programs and “may” look to partner with a battery storage company and community solar anchor tenant through the new Community Solar Green Tariff (CSGT) program.

On October 30, 2018, a Ruling was issued that denied the PAO’s motion for testimony and evidentiary hearings, determining that the current process of workshops and comments is sufficient to address specific information in the record. The PAO filed a follow-up motion on November 21, 2018 to allow for further discovery and record development around community selection and certain pilot projects. In general, the PAO has continued to express its dismay with the lack of due process in this proceeding.

On December 21, 2018, D.18-12-015 was issued that approved 11 pilot projects, which were selected to achieve the following objectives:

• Allows for gathering inputs to assess cost-effectiveness and feasibility during Phase 3

• Provides access to affordable energy options in participating pilot project host communities

• Reduces households energy costs for participating pilot project host customers

• Increases health, safety and air quality of participating host pilot project communities

• Tests approaches to efficiently implement programs

• Assesses potential scalability

Among the 11 pilots that were approved in this decision, the decision approved one energy storage proposal relevant to CESA members:

• A $10 million set-aside within SGIP’s Equity Budget for the pilot communities

• Fully subsidize BTM residential storage up to a cost cap of $11,979 per household, a level equal to the average total residential system costs, which assumes 829 systems would be provided

• Fully subsidize BTM “Community Service Storage” at community centers or schools up to a cost cap of $26,379

• Adopt a pilot community-specific income cap, not the existing SGIP Equity Budget income cap

Unlike the October 3 Ruling, the decision did not approve the natural gas pilots in the Allensworth or Seville communities, but it found that natural gas pilots will not be categorically excluded as pilots and may have the potential to provide new and useful information to inform assessments of economic feasibility in Phase 3, especially as California City residents generally desire natural gas. SoCalGas’ proposal for natural gas line extensions were found to have excessively high unit costs. PG&E was directed to further explore and develop the renewable natural gas microgrid or tank pilot project for Monterey Park Tract, with an emphasis on securing a dairy digester partner and more thoroughly assessing the costs and timeline of the proposed project.

In addition, the decision identified that a central objective of the pilots is ensuring that all households, including those occupied by tenants, experience bill savings as a result of the pilot and do not suffer negative unintended consequences. To accomplish this, the decision determined it is reasonable to require all pilot administrators to seek assurances from property owners that they will not significantly increase rents or evict tenants as a result of home improvements for at least five years following completion of pilot appliance installations, and that this should be attained through some form of agreement between the property owner and tenant.

Notably, CPUC President Michael Picker issued a Dissent that stated that this decision “has extended the CPUC beyond its core competencies and its statutory directives and has created an overly complicated program.” In addition, he identifies that increasing subsidies by providing direct payments or bill credits would seem to have been the most straightforward, rapid, and transparent approach to increase access to affordable energy. Lastly he highlighted concerns that the CPUC has allowed individual, financially interested organizations to shape program design.

On January 18, 2019, PAO submitted an Application for Rehearing (AFR) of D.18-12-015 because of the lack of due process given to assess and cross-examine the Pilot Team’s proposal, which was adopted in the decision.

On December 13, 2020, the Pilot Team submitted a PFM recommending that D.18-12-015 be modified to remove the eligibility threshold for pilot project participants in the communities of Allensworth, Alpaugh, Fairmead, and Le Grand, and to change the $5,000 per household cap on remediation for substandard housing to a community cap. As justification, the Pilot Team argued that estimates of CARE eligibility in the participating communities do not reflect the on-the-ground reality of these communities, including for “community leaders” who may have incomes above the set threshold. PAO and TURN submitted a response that argued that the arguments rehash prior position and contended that the statute does not require a pilot to subsidize all customers, irrespective of their actual financial conditions. The IOUs also opposed the PFM as not sufficiently demonstrating why D.18-12-015 presented barriers to participation.

On February 3, 2020, a Ruling was issued that sought additional information from parties on cost tracking and recovery for the new bill protection mechanism, as well as information that would support its determination on the aforementioned PFM, including a potential community survey to obtain more accurate data on the four communities.

On April 23, 2020, D.20-04-006 was issued that  approved with modifications the PFM filed by the Pilot Team, where D.18-12-015 would be modified to remove the income eligibility requirements for Allensworth, Alpaugh, Fairmead, and Le Grand and to state that all residents of these four communities are eligible for full participation in the pilots, including fully-subsidized appliances. The CPUC was compelled by PG&E’s confirmation of CARE eligibility rates in these communities. This modification was based on updated eligibility projections for the CARE program for residents of these communities that indicate that greater than 75% of the residents are eligible for CARE subsidies. However, the request to adopt a $5,000 per home remediation cap was denied since the PFM did not provide new facts or compelling new justifications. In response to comments to the PD, the CPUC commented on the risks of the CPUC delving into housing policy through the design of these pilots, such as in addressing the issue of substandard housing and remediation costs. As such, the CPUC found the pilot includes reasonable caps on remediation costs.

Pilots Implementation

On January 30, 2019 and February 26, 2019, a workshop and follow-up webinar were held to consider appropriate models for structuring an agreement between a property owner and tenant to ensure that the tenant experiences bill savings as a result of participating in the pilots and does not suffer unintended consequences. The purpose of this workshop was to solicit stakeholder feedback on the appropriate models for structuring such an agreement. The IOUs proposed that a three-year agreement be established with the landlord along with tenant consent. Based on its experiences in administering the SOMAH Program, GRID Alternatives proposed that the landlord signs the affidavits and that a permanent tenant agreement be established to prevent landlords from increase rent or evict tenants once signed. While tenant signature would not influence the owner signing the agreement, the Pilot Team discussed how tenant consent could greatly benefit in court. During the discussions, stakeholders considered whether a short time period should be established by which rents could not be increased and the appropriate entity to act as the enforcer of the agreements (IOUs, PAs, or CPUC).

On February 1, 2019, another workshop was held to present and solicit stakeholder feedback on bill protections and affordability approaches for households participating in the San Joaquin Valley pilots. GRID Alternatives presented their bill protection analysis and recommended that the CPUC authorize and fund a 20% electric bill discount lasting for 20 years for all pilot participants, reassess the bill discount during the evaluation stage, only allow for the CSGT Program as the community solar platform in pilot communities, and guarantee that all participants will receive community solar credits within three months of receiving home upgrades. The IOUs proposed a three-year credit that is adjusted over time based on data collection, including a customer’s individual propane and wood data. Most parties agreed on the need to leverage existing programs and explicitly displaying the credit in monthly electric bills, among other things. However, further deliberation was needed on defining bill savings, measurements for rebound effects, credit methodology, and bill protection duration.

On March 18, 2019, the IOUs and SoCalGas submitted advice letters that proposed a three-year bill protection approach for participation in the pilots and proposed that prospective pilot participants who reside in tenant-occupied households enter into an agreement with the owner of the property that would include various protections for tenants over a five-year period (e.g., limitations of annual rent increases and tenant evictions).

The Pilot Team and Greenlining Institute submitted a protest arguing that D.18-12-015 and AB 2672 requires bill savings, not just bill protection. Meanwhile, PAO protested the advice letters on the grounds that the proposals would not adequately protect customers experiencing the most extreme bill increases and because D.18-12-015 did not authorize a new bill credit. Instead, PAO proposed allocating the $500 per household budget across customers based on need and actual energy cost. GRID Alternatives proposed a longer-duration protection measure as well as a mechanism whereby participating pilot customers can receive a community solar discount right away regardless of income. Others proposed extending the tenant protection measures over a 20-year period. In general, the protesting parties proposed alternative solutions to ensure meaningful participant savings and to minimize the risk of overall energy bill increases, which together could undermine the success of the pilots.

In response, the IOUs and SoCalGas commented on how bill protection and tenant protection measures were already litigated and rejected in D.18-12-015. For example, it was already determined that the customer-specific approach would be too difficult to understand for customers and to implement by the utilities and that the 20-year, 20% bill protection solution was premature. The IOUs also recommended that CS-GT and DAC-GT program requirements be upheld (e.g., 5-mile locational requirement).

On March 19, 2019, the IOUs and SoCalGas submitted advice letters to propose their pilot implementation plans, which includes proposed pilot project budgets, timelines, workforce development plans, warranty measures, and other program details.

On May 7, 2019, a workshop was held to present and solicit stakeholder feedback on the reliability report format for the participating San Joaquin Valley communities. The report will analyze root causes of the outages in the participating San Joaquin Valley communities and timeliness for corrective action. PG&E and SCE presented on their current reliability programs (e.g., Worst Performing Circuits [WPC] Program) and looked at city-by-city SAIDI and SAIFI metrics that examine the duration and frequency of sustained outages (greater than 5 minutes in duration) in the pilot communities. On average, the analysis revealed that pilot customers experience slightly more outages per year (1.77) than the average customer (1.18) – i.e., one additional outage every two years. By contrast, pilot customers experience significantly better service restoration (1.25 hours) than the average customer (3.5 hours).

On December 4, 2019, a webinar was held to review the Community Energy Navigator Program Managers’ (CPM) Community Outreach & Engagement (CO&E) Plan. The Community Energy Navigator (CEN) will be key to the success of the pilot and will play a key role in educating SJV community residents through outreach activities and in assisting pilot communities to develop a cohort of local community leaders who can be a trusted resource for their community on energy issues. Self-Help Enterprises (SHE) was selected to be the CPM and has contracted with SCE to perform this role. CPM-CEN team includes Leadership Council for Justice and Accountability, Center for Race, Poverty and Environment, and the Association for Energy Affordability.

On December 23, 2019, Resolution E-5034 was issued that modified the “bill protection” programs proposed by PG&E and SCE for participants in the San Joaquin Valley electrification pilots as follows:

• All customers receive a 20% discount off their electric bill for the first five years of the pilot; vouchers are not permitted as a mechanism to distribute these credits.

• The utilities will evaluate bill impacts by comparing pre-pilot energy cost data from electric bills and voluntarily submitted propane expenses and propane modeling results against the post-pilot electric costs.

• At the end of five years, if any customer who is not a statistical outlier still experiences a bill increase, the 20% discount would continue for all customers for an additional five years. If all customers experience lower bills, then the bill discount would be reduced to 10% and would continue for another five years for all customers.

• Pilot participants will be provided with a 20% transitional community solar discount if they are unable to receive a 20% discount as part of the Community Solar Green Tariff (CS-GT) or Disadvantaged Communities Green Tariff (DAC-GT).

• This transitional community solar discount shall not apply to customers who have onsite solar through the Single-Family Affordable Solar Homes (SASH) Program or the Disadvantaged Communities SASH (DAC-SASH) Program, or through another program.

This contrasts with the IOUs’ three-year proposal to give $500 credit per pilot participant that would be adjusted over time based on propane and wood data collection throughout the pilot. The IOUs were opposed to these changes as being cost ineffective and not supported by the record. By contrast, low-income representatives recommended an extended duration of the bill protection discount to 15 years (instead of the proposed 5 to 10 years). Finally, PG&E and SCE must implement a billing process that enables them to provide pilot participants bill protection discounts by no later than May 1, 2020.

On April 16, 2020, Resolution E-5043 was issued to implement a split incentives agreement for pilot participants that mostly approved the IOU proposal for not creating overly burdensome enforcement mechanisms against property owners to ensure tenant protections. Specifically, the CPUC:

• Adopted provisions that prevent property owners from evicting tenants (except under certain circumstances) and increasing rent by more than 3.6% per year (based on 2018 CPI), unless the rent increase is due to increases in property taxes, O&M costs, or amortizing costs of other improvements

• Established a process for tenants to submit complaints to the community energy navigator

• Established a 5-year agreement term to protect tenants without restricting a property owner’s rights for an unreasonable length of time

• Required property owners to repay the costs of improvement for violating agreements

The CPUC generally found that the 20-year duration for agreements, as proposed by GRID Alternatives and other protestors, is inapplicable since the pilots will fund a mix of electrification and natural gas measures inside the units, in contrast to higher capital-intensive solar systems. The CPUC also declined to restrict the sale of the home for participating property owners. Generally, the CPUC erred on the side of not overly discouraging property owner interest and participation in the program while still ensuring certain tenant protections.