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Calif. PUC votes to provide storage incentives for low-income customers

October 26, 2020

by Paul Ciampoli
APPA News Director
October 26, 2020

The California Public Utilities Commission on Oct. 22 revised its Self-Generation Incentive Program (SGIP) to increase focus on supporting energy storage for low income customers and communities, medically vulnerable customers and facilities that provide critical services.

Specifically, the CPUC approved $108.5 million in additional funding for the SGIP “Equity Budget.” This funding provides incentives for customers who install energy storage systems and who are low-income residents or local governments, schools, nonprofits, or small business customers located in disadvantaged or low-income communities, or in Indian Country.

The CPUC noted that after it authorized increased incentive amounts for the Equity Budget in late 2019, customer demand for the program greatly increased.  All authorized funding was quickly allocated and waiting lists were created.

Last week’s decision does not increase the absolute amount of funding for SGIP, but transfers funds to the Equity Budget from funding set aside for general large-scale storage projects,  i.e., non-residential storage systems installed by customers that are not low-income or located in disadvantaged or low-income communities.

After the transfer of funds, the general large-scale storage budget will still have funding available for future projects.

The proposal voted on by the state utility commission is available here.

The SGIP was established in 2001 to increase deployment of distributed generation and energy storage systems to facilitate the integration of those resources into the electrical grid, improve efficiency and reliability of the distribution and transmission system, and reduce emissions of greenhouse gases, peak demand, and ratepayer costs.

Additional information about the SGIP is available here.

Glendale, Calif., utility wins approval for efficiency, DR programs

October 23, 2020

by Peter Maloney
APPA News
October 23, 2020

The Glendale City Council in California has unanimously approved multiple energy efficiency and demand response programs for Glendale Water & Power, the city’s public power utility.

The new clean energy programs are part of Glendale Water & Power’s efforts to reduce its reliance on fossil fuels. Last summer, the city council approved the utility’s plan to repower the aging Grayson Power Plant.

The Oct. 13 approvals included residential and commercial demand response programs, energy efficiency measures for commercial customers, and approval to begin negotiations for the development of a residential virtual power plant program.

The new demand response program would allow Glendale Water & Power to declare demand response events on peak days to reduce peak electrical load. Residential customers may participate in the program by using an existing smart thermostat and receiving a $50 incentive to join the program or by purchasing a new smart thermostat with a $100 discount through the program.

On peak days, Glendale Water & Power will adjust the temperature of the thermostats of participating customers to help reduce electrical demand. Residential customers will receive a $50 annual incentive for participating in the demand response program.

Commercial customers with demand of 50 kilowatts (kW) or greater are also eligible to participate and will receive a complimentary program site assessment to help identify load reduction strategies.

Commercial customers may join the program at two different levels: a 4-hour reduction ($10/kW-month or $50/kW-year) or a 2-hour reduction ($5/kW-month or $25/kW-year). Glendale Water & Power says the program will reduce peak energy demand by up to 10 megawatts (MW) on up to 15 peak days per year. Franklin Energy Services will provide services for the program.

The city council also approved an energy efficiency program for commercial customers that will provide eligible businesses with the direct installation of energy efficient lighting and heating, ventilation, and air conditioning upgrades. Glendale Water & Power expects the upgrades to reduce annual electric usage in the city by up to 35,000 kilowatt hours (kWh) and reduce demand by up to 8.3 MW. Lime Energy Services will be contracted to provide the services for the program.

The city council also directed Glendale Water & Power to complete negotiations with Sunrun for a proposed virtual power plant program that would provide solar generation and battery storage from 3,000 to 4,000 single-family residences and 30 to 40 multi-family properties.

The proposed program would deliver solar energy and an average of 25.25 MW of solar-powered battery storage each year to Glendale over 25 years and would provide backup power to participating customers in the event of a grid outage.

Once contract negotiations are complete, the contracts for the virtual power plant program will be presented to the city council for consideration. The utility says it would be the largest virtual power plant program of its kind.

After the contracts are finalized, Glendale Water & Power expects the new clean energy programs to get started early in 2021. When fully implemented, the utility expects the programs to deliver an average peak capacity of 38.4 MW.

“Our new clean energy programs show that Glendale is at the forefront of a clean energy commitment and will help transition GWP to have 100% renewable energy sources by 2045,” Steve Zurn, general manager of Glendale Water & Power, said in a statement.

The utility’s plan for the Grayson plant includes a 75 MW, 300 MWh battery storage system, as much as 50 MW of distributed energy resources that include solar photovoltaic systems, energy efficiency and demand response programs, and 93 MW of thermal generation from up to five internal combustion engines.

APPA holds virtual grading meeting to vet Reliable Public Power Provider applications

October 23, 2020

by Paul Ciampoli
APPA News Director
October 23, 2020

The American Public Power Association’s first-ever virtual grading meeting for Reliable Public Power Provider (RP3) applications was held this month.

“The COVID-19 pandemic prevented APPA from hosting the grading meeting in our offices this year,” noted Alex Hofmann, Vice President, Technical and Operations Services, at APPA. “However, the meeting went smoothly thanks to the flexibility and dedication of the RP3 Panel and guest veteran graders,” he said.

APPA’s RP3 program recognizes utilities that demonstrate high proficiency in reliability, safety, workforce development, and system improvement. Utilities keep the RP3 designation for three years.

APPA received 111 2020 RP3 applications. A total of 18 panel members participated in this month’s virtual grading meeting, as well as as well as six veteran graders.

The panel will be meeting virtually again at the beginning of December to finalize the grades after reviewing responses to requests for information that will be sent out to utilities the week of Oct. 26.

A total of 114 public power utilities earned the RP3 designation earlier this year from APPA and there are currently a total of 278 utilities with a designation.

EPA proposes to revise the Cross-State Air Pollution Rule Update

October 23, 2020

by Paul Ciampoli
APPA News Director
October 23, 2020

The Environmental Protection Agency on Oct. 15 proposed the Revised Cross-State Air Pollution Rule (CSAPR) Update in order to fully address the outstanding interstate pollution transport obligations of 21 states for the 2008 ozone National Ambient Air Quality Standards (NAAQS).

Starting in the 2021 ozone season, the proposed rule would require additional emissions reductions of nitrogen oxides (NOx) from power plants in 12 states.

The action addresses the remand of the CSAPR Update by the U.S. Court of Appeals for the D.C. Circuit on September 13, 2019, in Wisconsin v. EPA. The court found that EPA failed to fully eliminate significant contribution to nonattainment and interference with maintenance of the 2008 ozone NAAQS from upwind states by downwind areas’ attainment dates.

EPA is proposing that for 9 of the 21 states for which the CSAPR Update was found to be only a partial remedy (Alabama, Arkansas, Iowa, Kansas, Mississippi, Missouri, Oklahoma, Texas, and Wisconsin), their projected NOx emissions in the 2021 ozone season and thereafter will not significantly contribute to a continuing downwind nonattainment and/or maintenance problem.

Therefore, the states’ CSAPR Update federal implementation plans or the state implementation plans subsequently approved to replace certain states’ CSAPR Update Federal Implementation Plans fully address their interstate ozone transport obligations for the 2008 ozone NAAQS.

For the remaining 12 states (Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia), their projected 2021 emissions were found to contribute at or above a threshold of 1 percent of the NAAQS to the identified nonattainment and/or maintenance problems in downwind states.

EPA is proposing to issue new or amended federal implementation plans to revise state emission budgets that reflect additional emissions reductions from electric generating units beginning with the 2021 ozone season (May 1 – September 30).

The federal implementation plans would require power plants in the 12 linked states to participate in a new CSAPR NOx Ozone Season Group 3 Trading Program. The new program largely replicates the existing CSAPR NOx Ozone Season Group 2 Trading Program, with the main differences being the geography and budget stringency.

In addition, EPA is proposing to adjust these states’ emission budgets for each ozone season (2021-2024) thereafter until air quality projections demonstrate resolution of the downwind nonattainment and/or maintenance problems for the 2008 ozone NAAQS.

The emission budgets signify a control strategy that reflects the full optimization of existing selective catalytic reduction controls (SCRs), optimize idled SCRs and upgrades of low NOx burners for the 2022 ozone season, with an estimated marginal cost of $1,600 per ton. Based on EPA’s analysis the proposal is projected to result in a reduction of 17,000 tons of NOx during the summertime ozone season in 2021 and subsequent years.

EPA is proposing to authorize a one-time conversion of allowances banked from 2017 to 2020 under the CSAPR NOx Ozone Season Group 2 Trading Program into a limited number of allowances that can be used for compliance in the CSAPR NOx Ozone Season Group 3 Trading Program.

For non-electric generating units (EUGs) and emissions sources, EPA analyzed whether any emissions reductions should be required from non- EGUs to address significant contribution under the 2008 ozone NAAQS.

The agency’s analysis suggests that there are relatively fewer emissions reductions available at a cost threshold comparable to the cost threshold selected for EGUs.

Emission reductions from non- EGUs are estimated to have a relatively small effect on any downwind receptor in the year by which such controls could likely be installed. Therefore, EPA proposes that limits on ozone season NOx emissions from non-EGU sources are not required to eliminate “significant” contribution under the 2008 ozone NAAQS.

EPA is under a court order to finalize the proposal by March 15, 2021. There will a 45-day public comment period once the proposed rule is published in the Federal Register.

EPA plans to host a virtual public hearing in November 2020.

Missouri regulators open proceeding to determine long-term RTO membership benefits

October 22, 2020

by Paul Ciampoli
APPA News Director
October 22, 2020

The Missouri Public Service Commission has opened a proceeding to determine the long-term benefits of continued membership in a regional transmission organization (RTO) by the state’s investor-owned electric utilities.

“The Commission believes there are benefits in RTO membership but long-term costs and commitments of RTO membership, especially given the structure, services, and membership of both Southwest Power Pool (SPP) and Midcontinent Independent System Operator (MISO) continue to change significantly with the passage of time,” the PSC said in an Oct. 19 news release.

In order to determine whether continued membership in an RTO is in the ratepayers’ best interest, the PSC “must inquire into the nature of the benefits of RTO membership, the monetized value of those benefits, and what time horizons should be employed to compare asset lives (costs) to the values of benefits streams,” it said.

The PSC directed the state’s investor-owned utilities to take part in a workshop and cooperate with Commission Staff in its investigation.

PSC Staff and the electric utilities will determine:

PSC staff will file a report related to its findings by June 30, 2021.

The PSC order opening the proceeding is available here.

Calif. CCA Central Coast Community Energy receives “A” issuer credit rating

October 22, 2020

by Paul Ciampoli
APPA News Director
October 22, 2020

Central Coast Community Energy on Oct. 16 received an “A” issuer credit rating from Standard & Poor’s, which Central Coast Community Energy said is the highest rating received by a California community choice aggregator (CCA).

S&P’s issuer credit rating and “stable” outlook is an independent assessment of the CCA’s operational and financial strategies over the long term, “confirming the agency’s economic stability and footing for future success,” Central Coast Community Energy said in a news release.

Central Coast Community Energy “is proud to receive the first ‘A’ investment grade credit rating among California CCAs. This is a testament to the hard work and forward thinking” the CCA’s staff and leadership have demonstrated since launching in 2018, said Central Coast Community Energy Policy Board Chair and Santa Cruz County Supervisor Bruce McPherson.

“In that short time this agency has set a very high bar in terms of financial strength, operational responsibility, innovative energy procurement and energy programs, not to mention extending CCA benefits to the entire Central Coast,” he said.

The rating will allow the CCA “to embark on an even more impactful path towards reducing greenhouse gas emissions through local energy programs and energy procurement,” and it helps to ensure the “longevity and continued success” of the CCA on behalf of its communities.

Central Coast Community Energy said that the rating recognizes the CCA’s stability within the California CCA market and the strong socio-economic conditions of its growing service area.  

Central Coast Community Energy serves more than 400,000 customers throughout the Central Coast, including agriculture, commercial and residential customers in communities located within Monterey, San Benito, San Luis Obispo, Santa Barbara and Santa Cruz counties.

S&P’s rating action emphasized the CCA’s strong economic fundamentals, comprehensive governance structure, robust energy risk management policy, and experienced executive leadership as contributing factors to its being the first CCA to receive an ‘A’ rating and “stable” outlook.

The rating enables the CCA to continue providing electric service and innovative energy programs at competitive rates to its 33 member agencies and over 400,000 agriculture, commercial, and residential customers, Central Coast Community Energy said.

In addition, the rating will aid in increasing the number of counterparties competing for Central Coast Community Energy wholesale contracts, lower transaction costs, and make innovative financing structures accessible to help the CCA continue to develop solutions to California’s greatest energy challenges, Central Coast Community Energy said.

The American Public Power Association has initiated a new category of membership for community choice aggregation programs.

AVANGRID to acquire New Mexico-based IOU PNM Resources

October 21, 2020

by Paul Ciampoli
APPA News Director
October 21, 2020

Connecticut-based energy company AVANGRID will acquire New Mexico investor-owned utility PNM Resources in a transaction with an $8.3 billion enterprise value, the companies announced on Oct. 21.

As a result of the transaction, which has been approved by the boards of the two companies, PNM’s shareholders will receive approximately $4.318 billion in cash. 

PNM said that the transaction will create a large, diversified national regulated utility and renewable energy platform with approximately $14 billion of rate base and more than four million electric and natural gas utility customers.

AVANGRID is the third largest wind operator in the U.S. and has more than 7.5 gigawatts of installed wind and solar capacity.

“The strategic combination with PNM Resources also provides a platform for AVANGRID to expand its renewables business in the Southwest beyond its existing 1.9-gigawatt capacity wind projects in New Mexico and Texas and 200 megawatts of wind and solar capacity in Arizona,” PNM said in a news release.

PNM said it remains committed to exiting coal

PNM said it remains committed to exiting coal through the approved abandonment of San Juan Generating Station in 2022 and the continued efforts to exit its 200-megawatt ownership interest in the Four Corners Power Plant earlier than originally planned. The plants are located in New Mexico.

PNM said that it sees the potential for additional customer savings by exiting the plant sooner than the expiration of the ownership and coal supply agreements in 2031. “An earlier exit from Four Corners also opens the door for the combined company to bring additional renewable resources onto the grid in support of New Mexico’s increasing renewable energy standards and 2045 carbon-free mandate,” it said.

The transaction is subject to PNM Resources shareholder approval, regulatory approvals from the New Mexico Public Regulation Commission, Public Utility Commission of Texas, Federal Energy Regulatory Commission, Department of Justice, Nuclear Regulatory Commission, Federal Communications Commission and Committee on Foreign Investment in the United States, and other customary closing conditions.

The transaction is expected to close between October and December 2021.

Connecticut-based AVANGRID has two primary lines of business: Avangrid Networks and Avangrid Renewables.

Avangrid Networks owns eight electric and natural gas utilities, serving more than 3.3 million customers in New York and New England. Avangrid Renewables owns and operates a portfolio of renewable energy generation facilities across the United States. Spain’s Iberdrola owns 81.5% of the outstanding common stock of AVANGRID.

Through its regulated utilities, Public Service Company of New Mexico and Texas-New Mexico Power, PNM Resources has approximately 2,811 megawatts of generation capacity and provides electricity to approximately 790,000 homes and businesses in New Mexico and Texas.

Texting saves time for utility and its customers

October 21, 2020

by Peter Maloney
APPA News
October 21, 2020

Rock Hill Utilities, a South Carolina public power utility that began using text messages as an outage notification tool in May, is now looking at expanding its use for other functions to save time and money.

Rock Hill Utilities uses texting to automatically send outage notifications to affected customers, saving time for both the customer and the utility. Customers can also send texts to the utility to report outages. And, with the text messaging system directly connected to the utility’s outage management system, it can pinpoint the location and extent of an outage and possibly help isolate the cause and even provide data for predictive analysis.

Texting has greatly cut down on the calls that utility staff have to handle while providing quicker, more accurate communications with customers, Mike Jolly, director of utilities for Rock Hill Utilities, said. Now, when the utility declares an outage, a message is sent automatically to customers.

“We had a large outage a couple of weeks ago. In the past, we probably would have had hundreds of calls. We had two,” he said.

Customers appear to be enthusiastic as well. About 95% of customers have chosen to participate in the text service, which is provided by TextPower, a company based in San Juan Capistrano, California, that provides text messaging solutions for mission-critical applications at over 140 utilities across the country.

Almost immediately after it began using TextPower for outage notifications, Rock Hill Utilities formed a team to begin exploring what other uses the utility might perform using texting services. “I started thinking, ‘How much time and money could we save?’” Steven Varnadore, the utility’s power and communications manager, said. “It makes us more efficient and saves overtime and truck rolls.”

In June, the utility began using the texting service to send a daily inspirational message to its employees. The exploratory team is now looking at several other uses. “There has been a lot of discussion about customer service and billing,” Jolly said.

Rock Hill Utilities runs a combined utility system that provides electric, water and sewer services to about 95,000 people in the city and the surrounding area. The region has a lot of apartment buildings and a lot of people moving from one apartment to another. For the utility, that means move-ins and move-outs are frequent, Lori Thomas, operating revenue administrator for Rock Hill, said.

Texting allows the utility to push out a text message to confirm dates and locations with a greater accuracy and higher response rates. Typically, that was a function the utility did with email. “Almost everyone has a smart device in their hand, but not a laptop to check their email,” Thomas said.

Another function Rock Hill Utilities is looking at is using texting for is disconnect notices for non-payment. The utility currently uses a phone tree for those notices but reaching the customer can be difficult since land line numbers can change.

For quick and reliable communication, texting has many advantages, Mark Nielsen, TextPower’s executive chairman, said. About 59% of U.S. households no longer have a land line, instead using their cellular phone as their primary number, Nielsen says. And, compared with other forms of communication, text message response rates are high. Almost all text messages are read, and 95% are read within three minutes of being received.

Other platforms, such as Facebook and Twitter, are useful, says Nielsen, but only about 30% of followers see a given tweet and only 16% of Facebook followers see a given post. Most importantly, he says, the percentage of customers who follow their utility ranges from less than 1% to maybe 25%.

In addition, Nielsen points out that less than 2% of text messages are spam, so customers are less likely to ignore them than they would a phone call or email.

In part, that is because of protections built into the Telephone Consumer Protection Act (TCPA), which restricts the way businesses can use text messages, though there is a specific ruling by the FCC relating to utilities. Texts should relate to a utility’s service and not be used to sell a service or product (informational or emergency communications). And the utility should provide an easy way for a customer to opt out of the service, such as replying “Quit” or “Stop”.

The best way to bring customers into the service is to enroll them with an opt-out option, rather than an offer that allows them to opt in, says Varnadore, who noted Rock Hill’s high retention rate for text-enabled customers.

Varnadore has also found that texting has brought some changes to the way the utility operates.

In the past, customers would call in outages, and a dispatcher would collect the information and declare an outage. The lag time involved in using phones built in room for discrepancies to be cleared up as the process went along.

With texting, however, “we have to follow outages more closely and update restoration times more accurately,” Varnadore said. Any accidental declaration of an outage is likely to be corrected by customer feedback, he said. “It causes more precision on our end and staying up on the outage.” Nonetheless, he said, the benefits outweigh some of the changes the utility had to make.

Rock Hill Utilities is also using TextPower to send customer notices for scheduled repair and maintenance work. And the utility is exploring expanding the use of texting to enable customers to send in notices about other safety concerns, such as water or sewer leaks, and wants customers to be able to text photos as a way of better equipping repair crews to respond to problems more appropriately and accurately.

Expanding texting capabilities had been on the utility’s “road map” for quite a while but was put on hold while the utility replaced about 70,000 meters with advanced metering infrastructure (AMI).

That project wrapped up about 18 months ago, and Rock Hill Utilities revisited its texting options.

Looking back, the lesson learned is “not to wait so long,” Jolly said. “I’m glad we did it. I wish we had done it earlier.”

For more information about TextPower, visit the company’s website.

FERC approves CAISO’s EV, storage-related demand response proposals

October 21, 2020

by Peter Maloney
APPA News
October 21, 2020

The Federal Energy Regulatory Commission (FERC) has approved tariff revision proposals by the California Independent System Operator (CAISO) designed to enhance demand response using electric vehicle charging stations and energy storage.

The first proposal allows electric vehicle supply equipment (EVSE) to participate in CAISO’s demand response program independently from a host facility.

CAISO said it is seeing a growing number of EV charging stations at large load centers like grocery stores, movie theaters, and offices that frequently operate under the same retail meter and account as their host. Thus, the entire facility must participate as a single metered resource even though the load profiles of the charging station and the host may be very different.

CAISO told FERC that failing to capture the unique load profile of the charging station may send the wrong price signals to the owners of electric vehicles.

To enhance demand response participation in its markets, CAISO proposed allowing EVSE to be treated as a separate load curtailment measure when providing demand response at facilities with onsite load.

CAISO’s proposal does not require those resources to separate EVSE from the rest of their load but, where demand response resources elect to measure EVSE performance separately, CAISO will require the resource to sub-meter the EVSE to avoid co-mingling the EVSE load and the onsite host load’s performance.

The EVSE and onsite host load will continue to operate under a single resource identity and to bid and meet CAISO schedules together as a single resource but will be settled separately based on their individual baselines.

In addition, a proxy demand resource can consist entirely of one or more EVSE resources, with no onsite load, and nothing requires the demand response provider to include onsite load in a proxy demand resource consisting entirely of EVSE. CAISO said the revisions would provide transparency and more accurate price signals for EVSE and onsite load that participate in demand response programs.

In the order, (ER20-2443-000), FERC agreed with CAISO that the revisions would “better capture EVSE’s distinct characteristics, provide more accurate price signals to EVSE owners, and create incentives for them to participate in demand response programs.”

In the second proposal, CAISO requested that behind-the-meter energy storage be required to submit separate bids, for a consumption resource when charging and for a curtailment resource when discharging.

Each bid would have a separate resource identification and its own baseline and demand response energy measurement to establish typical use, using methodologies nearly identical to CAISO’s existing metering generator output methodology.

FERC said that accounting for both energy storage functions “should provide incentives for behind-the-meter energy storage resources to consume energy during oversupply conditions and supply energy during periods of high demand,” enhancing reliability and market efficiency and potentially increasing participation in demand response programs.

FERC, in the Sept. 30 order, also granted CAISO’s request to set the effective date for both proposals to Oct. 1.

CAISO board OKs storage and DER enhancements

In a separate action, CAISO’s board of directors on Oct. 2 approved energy storage and distributed energy resource enhancements designed to make it easier to integrate and operate those resources while maintaining grid reliability, and authorized CAISO management request FERC approval of the proposal.

The approval of Phase 4 of the Energy Storage and Distributed Energy Resources (ESDER 4) enhancements included:

CAISO noted that batteries, both stand alone and hybrid, are fast growing components of the resource mix, with more than 1,500 MW scheduled to connect to the grid by the end of 2021.

California community choice aggregators issue RFO for long-duration storage

October 20, 2020

by Peter Maloney
APPA News
October 20, 2020

Eight Community Choice Aggregators (CCAs) in California late last week launched a joint request for offers (RFO) to procure up to 500 megawatts (MW) of long-duration energy storage.

The RFO was issued on Oct. 16 by Central Coast Community Energy, CleanPowerSF, Marin Clean Energy, Peninsula Clean Energy, Redwood Coast Energy Authority, San Jose Clean Energy, Silicon Valley Clean Energy, and Sonoma Clean Power.

The CCAs are looking to sign a minimum 10-year contract for grid-charged technologies in the form of one or more projects that would come online by or before 2026 with a minimum discharge period of eight hours. Responses to the RFO are due by Dec. 1.

“By working together, the eight CCAs are able to procure large-scale projects that would be challenging for one CCA to procure on its own,” Girish Balachandran, CEO of Silicon Valley Clean Energy, said in a statement. “Collaborating on this long-duration storage solution allows the CCAs to manage financial and technology risks while still diversifying portfolios with cost-effective and innovative resources.”

The CCAs say long-duration energy storage will do more to help support higher concentrations of renewable energy on the grid. Most of the energy storage devices deployed to date have durations of about four hours, which can provide energy for a few hours in the evening after solar power resources fade.

The CCAs are looking for long-duration storage that would be able to charge from the grid when renewable resources are at their peak and discharge for eight to 16 hours when renewable production is lower.

A recently released preliminary analysis by the California Independent System Operator, the California Public Utilities Commission, and California Energy Commission into the root causes of the state’s Aug. 14 and 15 rotating outages found that the simultaneous decline of solar power and rise of demand in the evening has resulted “multiple critical periods during the day” rather than a single peak. The report recommended the procurement of more resources, including energy storage, and changes to the state policies to address the new challenge of “net peak demand.”

The CCAs say the addition of long-duration storage to their portfolios will aid renewable integration on the grid while advancing California’s aggressive greenhouse gas reduction targets for 2030.

Earlier in 2020, the joint CCAs issued a Request for Information for long-duration storage and received more than 58 project entries with 14 different technologies, which they said signaled “significant supplier interest.”

The RFO is available here.

The American Public Power Association has initiated a new category of membership for community choice aggregation programs.