DEED project demonstrates costs and benefits of reclosers in Florida
January 12, 2021
by Peter Maloney
APPA News
January 12, 2021
Replacing fuses with reclosers can lead to a “notable” reduction in the number and duration of outages, according to the results of a Demonstration of Energy & Efficiency Developments (DEED) project in Florida.
The project, Demonstration Project to Achieve Cost Effective Reliability Improvement Using Single Phase Reclosers, involved the demonstration of advanced reclosers at three Florida utilities: the Town of Havana, Keys Energy in Key West, and the City of Tallahassee. The Florida Municipal Power Agency (FMPA), an Orlando-based wholesale power agency, applied for the DEED grant and managed the project on behalf of the member utilities.
The TripSaver II Cutout Mounted Recloser manufactured by S&C Electric was selected for the project because of the low installed cost, ease of installation and reported success by some FMPA members who have installed TripSavers on their systems.
A circuit selection methodology was developed for the project and 13 reclosers were installed at each of the three utilities for a total of 39 reclosers.
FMPA’s report on the DEED project noted that legacy recloser designs are bulky, contain oil and lack communication and data recording capability while newer designs are more compact, less costly, and do not use oil making them highly desirable for single-phase applications.
Despite the advantages of more recent design reclosers, the report noted that FMPA member cities face barriers such as lack of internal staff to lead a reliability initiative, lack of engineering support to analyze their network and select recloser locations, and a perceived high cost relative to the reliability benefit.
“The TripSavers installed in two cities experienced fewer faults than what was expected given the laterals’ outage history,” according to FMPA’s report on the DEED project.
A decline in storms and wildlife activity may have resulted in reduction of outages, but further analysis will be required to determine the influence of external factors on the project’s results. Nonetheless, “it was proven that even a limited deployment of reclosers could have a significant impact for a small system” and in a “much larger system, results indicate that replacement of a small percentage of lateral fuses with TripSavers reclosers could yield “notable” improvements in both System Average Interruption Frequency Index (SAIFI) and System Average Interruption Duration Index (SAIDI) metrics, according to the report.
If utilities interested in pursuing a lateral recloser deployment target their worst performing laterals regardless of the feeder they could expect results “better than those achieved in this project,” according to the DEED report.
The report also noted that many utilities, particularly the smaller ones, struggle with the same barriers to deploying advanced reclosers that some FMPA members face.
“It is FMPA’s hope that the accomplishments of this project will be helpful in assisting other members wishing to deploy single phase reclosers as a cost-effective means to improve their system reliability,” the report concluded.
Specifically, FMPA said the project could provide guidance on circuit selection criteria, actual performance data, and an indicative range of investment costs necessary to avoid a single customer interruption.
The DEED grant from the American Public Power Association awarded FMPA $64,400 to carry out the project. FMPA, the three participating cities, and S&C Electric also contributed funding for the project, bringing the total budget to $134,000.
DEED members can read more about the project, Demonstration Project to Achieve Cost Effective Reliability Improvement Using Single-Phase Reclosers, on the DEED project database.
A webinar related to the project is scheduled for Jan. 28. For additional details, click here.
NERC: Long-term resources are sufficient, except in Ontario and MISO
December 17, 2020
by Peter Maloney
APPA News
December 17, 2020
There should be sufficient resources to meet electric power demand over the next 10 years, except in two areas, according to a new report from the North American Electric Reliability Corp. (NERC).
NERC’s 2020 Long-Term Reliability Assessment estimated there would be adequate resources except in Ontario and the Midcontinent Independent System Operator (MISO) regions where projected reserve margins could fall below reference margin levels.
And while bulk power system capacity is sufficient in the other areas of North America, some areas demonstrate the potential for insufficient resources. Specifically, NERC identified “nearly all parts of the Western Interconnection,” the Electric Reliability Council of Texas (ERCOT) area and MISO as areas that “show levels of increased risk over the next five years.”
Overall, NERC’s long-term assessment noted that “the addition of variable energy resources, primarily wind and solar, the continued growth of distributed energy resources (DER) and the retirement of conventional generation are fundamentally changing how the grid is planned and operated.”
“As the system becomes more reliant on wind and solar generation, resource and energy adequacy must be assured,” Mark Olson, manager of reliability assessments at NERC, said in a statement. “The changing resource mix introduces greater variability, making long-term planning more complex. To meet this challenge, we need to create the necessary models, technology, and strategies to properly support future grid operators.”
The report also noted that throughout the 2021-2030 assessment period and particularly in the years between 2021 and 2025 there is “heightened uncertainty in demand projections” stemming from the ongoing COVID-19 pandemic.
The pandemic does not present a specific threat to the reliability, but it does lead to uncertainty in electricity demand projections and presents cyber security and operating risks that could exacerbate planning reserve shortfalls in areas that are below or near NERC’s reference margin levels, the report found.
With respect to the two areas of highlighted concern, reserve margins in Ontario could dip below recommended levels as soon as 2022, driven largely by refurbishments of nuclear power plants, demand forecast uncertainty, and the expiration of several generation contracts, NERC said in the assessment, which was released Tuesday. Ontario’s Independent Electric System Operator expects to acquire the required electricity resources through capacity auctions or other tools.
In MISO, NERC said there are adequate reserves in the short term, but there could be shortfalls in 2025. MISO and stakeholders will need to take action to ensure future resource adequacy by “achieving certainty of prospective resources beginning in 2025,” NERC said.
One of the challenges posed by the increasing level of intermittent resources on the grid is that it introduces a risk of inaccuracy into demand forecasts, NERC said. The output from those units can be inaccurate, but in areas with “embedded solar PV” demand forecasts can also be inaccurate. The result, according to NERC, is “operators must increasingly balance uncertain loads with uncertain generation.”
Additionally, as more flexible resources, mostly natural gas-fired generation, are added to the system to make up for the intermittent nature of wind and solar power, NERC noted the potential for an increase in “vulnerabilities associated with natural gas delivery to generators” that could potentially result in generator outages due to both insufficient natural gas infrastructure or alternate fuel delivery and/or disruption to natural gas or alternate fuel deliveries.” Those risks are most notable in New England, the desert Southwest, and California, where there is increased reliance on natural gas generation and limited back-up fuel, the report said.
To address the emerging risks and prevent the possibility of threats similar to those posed in Ontario and MISO occurring elsewhere, NERC recommended that regulators and policymakers “coordinate with electric industry planning and operating entities to develop policies that prioritize reliability, such as promoting the development and use of additional flexible resources, energy-assured generation, and resource diversity.”
NERC also recommended that regulators and policy makers consider revising their resource adequacy requirements to consider new risks that emerge during non-peak hours, limitations from neighboring systems during system-wide events, and the reduced resource diversity and/or increased reliance on a single fuel source or delivery mode.
Industry should also “identify and commit flexible resources to meet increasing ramping and load-following requirements” that result from increased variable energy resources and not solely to meet peak load capacity requirements, the report said.
Clark Public Utilities commission approves budgets for electric, generating and water systems
December 2, 2020
by Paul Ciampoli
APPA News Director
December 2, 2020
The Clark Public Utilities commission on Dec. 1 voted to approve annual budgets for the electric, generating and water systems. Rate increases are not required to fund the approved electric and water utility budgets, the Washington State public power utility noted.
The 2021 operating revenue budget for the electric system is $384.8 million, compared to $382.5 million in 2020. As in years past, power supply remains the majority of the budget at $225 million — down from $230 million in the 2020 budget — and the operating and maintenance budget is $62 million.
The remainder is comprised of taxes, debt service, rate-funded capital and energy efficiency program funding, Clark Public Utilities noted in a news release.
The 2021 generating system operating revenue budget is $68.9 million, compared to the 2020 budget of $76.3 million.
Commissioners also approved a $21.6 million water system operating revenue budget for 2021, compared to $20.3 million in 2020.
Capital budgets for the electric, water and generating system all allocate funds for system maintenance and improvements.
For the electric and generating systems, projects planned for the combined $50.5 million capital investment include ongoing treatment and replacement of aging underground cable, substation, transmission and distribution line construction and upgrades.
The $10.9 million water system capital budget allocates funds for main extensions and upgrades and automatic meter reading equipment, among other improvements.
“This budget demonstrates our utility’s commitment to providing our customers with outstanding customer service and reliability while going to great lengths to control costs and be good stewards of our customers’ resources,” said Jane Van Dyke, president of the Clark Public Utilities Board of Commissioners.
Clark Public Utilities is a customer-owned public utility that provides electric service to more than 210,000 customers throughout Clark County, Wash. The utility also provides water service to about 37,000 homes and businesses.
Clark Public Utilities has been ranked highest in customer satisfaction among midsize utilities in the west by J.D. Power twelve years in a row.
Analysis finds adequate Eastern Interconnection frequency response
November 24, 2020
by Ethan Howland
APPA News
November 24, 2020
The Eastern Interconnection should be able to maintain system frequency for at least the next five years, according to a group of transmission planning coordinators.
However, with the addition of non-synchronous generation (intermittent wind and solar) and planned power plant retirements, maintaining frequency in the Eastern Interconnection is a concern that warrants continued study, the Eastern Interconnection Planning Collaborative (EIPC) said in a report issued Nov. 11.
The Eastern Interconnection electric grid covers about two-thirds of North America from the Rocky Mountains to the East Coast.
The North American Electric Reliability Corporation asked the EIPC, a coalition of 19 transmission planning coordinators, to study how the changing resource mix could affect frequency response in the Eastern Interconnection.
Frequency response is a measure of the grid’s ability to stop and stabilize frequency changes after the sudden loss of generation or load. If unchecked, sharp frequency changes can lead to power outages.
Load along with large fossil-fueled and nuclear power plants provide inertia to help maintain the grid’s frequency, but some plants are being replaced with renewable resources, which until a 2018 decision by the Federal Energy Regulatory Commission generally didn’t provide frequency response. To help maintain the grid’s stability, FERC ordered that all new generating facilities be able to provide frequency response.
The loss of inertia from the large power plants could trigger “under-frequency load shed” events, or blackouts, according to the EIPC.
At NERC’s request, the EIPC finished an initial frequency response study in April 2019.
“As the generation resource mix continues to evolve over time to incorporate new and emerging technologies and address energy and environmental policies, it is essential to understand how the Eastern Interconnection will be poised to maintain system frequency under a wide range of operating conditions,” said Keith Daniel, senior vice president of transmission policy at Georgia Transmission Corp. and chairman of the EIPC Executive Committee.
The EIPC task force that wrote the report studied four hypothetical events, including including generation losses of 2,300 megawatts, 3,850 MW and 4,500 MW as well as a 10,000 MW event.
The EIPC’s Frequency Response Working Group will continue to update its analysis, according to Daniel.
The EIPC is conducting additional power system analysis that will provide information to help maintain grid reliability and to inform state and federal regulators and policy makers, Daniel said.
The EIPC’s frequency response analysis will supplement NERC’s 2021 Long-Term Reliability Assessment.
The EIPC members include public power entities Municipal Electric Authority of Georgia (MEAG Power) and Santee Cooper.
NERC sees no reliability problems this winter but warns of fuel supply risks
November 23, 2020
by Peter Maloney
APPA News
November 23, 2020
There will be sufficient resources in service to meet electrical demand during the upcoming winter season, according to the latest reliability assessment by the North American Electric Reliability Corp. (NERC), but the organization also cautioned that there are continuing risks regarding supplies of natural gas in New England, California and the Southwest.
NERC’s 2020-2021 Winter Reliability Assessment covers December, January and February. The report found that anticipated reserve margins will meet or surpass reference reserve margins in all areas under normal conditions.
Sufficient fuel supplies, specifically of natural gas, remains a concern in some areas, however, as demand for natural gas, both as a fuel for power generation and for space heating, continues to grow, NERC said.
During particularly cold weather generating units that lack alternate fuel sources or that do not have contracts for firm fuel delivery may not be able to meet demand, the report noted.
In New England, where natural gas availability is limited, firm load would still be able to be served even under abnormally cold conditions, but under more severe conditions, such as those experienced in January 2018, limited oil inventories could lead to “eventual loss of generation and firm load shed,” NERC said.
The NERC report also noted that California and the southwest area in the Western Interconnection could face “fuel supply curtailment or disruption from extreme events that impact natural gas supplies,” as those regions rely on natural gas-fired generation capacity for over 60% of on-peak demand and have limited gas storage.
Overall, extreme weather conditions – such as wind generation blade icing, frozen coal piles, and curtailment of natural gas pipelines – continue to pose a risk to the bulk power system during the winter, NERC said. Unusually cold temperatures could result in increased demand and higher levels of generation forced outages and create conditions that would lead system operators to take emergency actions.
The NERC report also examined ongoing impacts from the COVID-19 pandemic, which it said is causing “increased uncertainty in electricity demand projections and presents cybersecurity and operating risks.” The reliability organization noted that no specific threats or degradation to reliability have been identified for the winter season. However, the report also noted that if maintenance operations on generation and transmission assets are not able to be performed because of the pandemic, “forced outages may escalate.”
The pandemic could also affect the accuracy of demand projections in the near term and have the potential to exacerbate or alleviate planning reserve shortfalls in areas that are below or near reference margin levels, NERC said.
NERC’s assessment also noted that restoration efforts in response to the recent hurricane season could continue into the winter. While restoration efforts in Arkansas, Texas, and north Louisiana have been completed, restoration work that is often characterized as a rebuild, continues in southwest Louisiana, primarily in and around the city of Lake Charles.
California PUC opens proceeding to address extreme weather events
November 20, 2020
by Paul Ciampoli
APPA News Director
November 20, 2020
The California Public Utilities Commission (CPUC) on Nov. 19 launched a rulemaking that it said will address how to increase energy supply and decrease demand during peak hours if a heat storm occurs in the summer of 2021 so the state does not experience a repeat of rolling power outages.
Through the proceeding, the CPUC will implement temporary changes to existing processes, programs, and rules for demand response, and other initiatives, it said.
The CPUC will focus on near-term actions that can be adopted by April 2021 and that the utilities can implement before the summer of 2021.
The proceeding will consider multiple options, including, but not limited to:
- Evaluating a mechanism for encouraging load shifting by compensating customers for switching to back-up generators;
- Modernizing the California Independent System Operator’s Flex Alert program by expanding its application to social media (e.g., paid advertising content) and consumer devices;
- Engaging various customer groups in load reduction programs, such as new event-based demand response programs or revising existing supply-side reliability demand response programs; and,
- Directing each investor-owned utility to develop new supply-side resources that can be brought online in 2021 and to bring additional capacity online by procuring incremental capacity from the existing resources, implementing efficiency upgrades to existing generators, and retrofitting existing generators.
The CPUC also said it will address whether particular measures may extend beyond calendar year 2021. Moreover, the CPUC will consider whether specific measures would be triggered only in emergency conditions to ensure continued access to utility services.
In mid-August 2020, the western U.S. experienced an unprecedented, prolonged heat storm, which led to a variety of circumstances that ultimately required CAISO to initiate rotating power outages to prevent sustained, wide-spread service interruptions.
On October 6, 2020, the California Energy Commission, CAISO, and the CPUC issued a preliminary report on the causes of the August rotating outages, which outlined short-term and longer-term actions to mitigate electricity shortages and ensure delivery of clean, reliable, and affordable energy.
The proposal is available here.
Austin Energy ADMS upgrade advances with COVID-19 safety protocols
October 29, 2020
by Peter Maloney
APPA News
October 29, 2020
Deploying an Advanced Distribution Management System (ADMS) is challenging in the best of times. Deploying an ADMS upgrade during COVID-19 only adds to the challenges.
Texas public power utility Austin Energy had “robust policies” in place to guard against the spread of COVID-19 before its ADMS upgrade, but for the in-person portion of the system operator training sessions related to the software upgrade, they decided to take “a lot of extra precautions,” Danny Ee, Austin Energy’s Director of System Operations and Advanced Grid Technologies, said.
“It was one of the most difficult decisions in my career to elect for a remote go-live during the pandemic,” Ee said. “However, we were determined to deliver the upgraded functionality despite the additional challenges and had the support of senior management and dedicated employees that were well prepared to make it a seamless upgrade.”
ADMS software monitors and optimizes a wide array of utility functions, including integration with outage maps, tie-ins with GIS mapping tools, notifications for utility field workers, distribution grid optimization, as well as providing analytical planning tools.
“ADMS is similar to Emergency Room triage for the healthcare industry,” Ee said. “It helps assess severity of issues, prioritize, and dispatch the appropriate staff to keep Austin’s power going. Without it, we would not have visibility to our grid and the ability to remotely control field equipment.”
Austin Energy deployed its first ADMS system in June 2014.
By 2020, it was time to upgrade to a newer version of the software. The upgrade, which went live in September, was the culmination of more than two years of preparation and was so extensive, “it was almost like installing a brand new system including all new servers and network infrastructure and extended the ADMS system user base by over 600 employees,” Ee said.
The ADMS Upgrade Project was focused on making a good thing better, Ee said. A good portion of the upgrade delivered improvements to usability, situational awareness, visualization and functionality that will improve monitoring, decision-making, optimization, reliability and security assessment of the electric grid and its components.
The ADMS Upgrade delivered expanded and enhanced functionality to existing system users and added applications for mobility/field crews and call centers. The new groups of users will have direct access to more information, which will help resolve customer outages more efficiently.
“The grid is changing, utilities are changing, and we have to be prepared,” Ee said. ADMS is an important tool in the transformation from a utility with one-way power flows to a smart utility that is continually responding to real time inputs and integrating multi-directional power flows, he said.
Austin Energy began implementing safety protocols related to COVID-19 early on. The City of Austin declared a local disaster in early March, allowing the utility to offer aid to customers having trouble paying their bills.
And, through a mix of new protocols and processes, Austin Energy has kept its employees safe and its operations running smoothly throughout the pandemic. About 1,400 of the utility’s 2,000 employees are now working from home.
Ee said the ADMS Upgrade deployment was supported completely remotely and was “intimidating” because the project teams were depending on on-site presence for several weeks leading up to the event, as well as on-site stabilization support after go live. Despite the change in plans due to COVID-19 restrictions, Ee said he is proud how the team worked through the implementation.
To keep employees safe through the pre-deployment system operator training, Ee and his team drew up an eight-page document of protocols. The training plan allows for only one trainer from the vendor, Mosaic, to be onsite. The trainer drove from Tulsa, Okla., to Austin, instead of flying, and quarantined for about one week before training began. The trainer also agreed to an initial COVID-19 test and restrict his movements to his hotel and Austin Energy facilities for the duration of the training.
The trainer and the employees participating in the training, in addition to following regular COVID-19 safety protocols, such as wearing face masks and washing hands frequently, also agreed to regular temperature checks.
Austin Energy marked off six-foot perimeters around the work stations that will be used during the training, provided daily cleaning and has limited the areas of the utility’s facilities that can be accessed by the trainer and trainees.
The utility is also providing boxed breakfasts and lunches and bottled water to the participants. The pre-deployment system operator training course lasted four days and was limited to three or four trainees within the same shift per course to prevent cross-contamination. Six weeks of courses were scheduled.
Post-deployment in-person field crew training is ongoing – it will last until December – and sessions that are underway currently are focused on situational awareness and efficiencies that are now available to the Field crews.
“ADMS will bring us to the future,” Ee said. He credits the utility’s robust safety and health protocols with winning the support of management and employees alike. “I am pleased to report that the employees that were offered in-person training are a dedicated bunch of individuals that chose to participate in training despite these uncertain times. I’m honored by the commitment that is continually demonstrated. The high buy-in is what made it successful.”
DOE partnership to help remote and island communities improve electric service
October 26, 2020
by Peter Maloney
APPA News
October 26, 2020
The Department of Energy (DOE) has announced a partnership that aims to support remote and islanded communities seeking to transform their energy systems and lower their vulnerability to energy disruptions.
The Energy Transitions Initiative Partnership Program (ETIPP) draws together resources from several DOE offices and laboratories that will work with five community groups.
Together the partners will work with competitively selected communities to plan for, withstand, and recover from disruptions. In fall 2020, communities will be able to apply to participate in the multi-year program.
The ETIPP partners will identify and advance strategic, tailored technological solutions designed to bolster community resilience and reduce economic risk for the selected communities.
The targets of the program include 31 rural villages in Alaska prone to flooding and erosion, inland American Indian reservations in rural Northern California at risk of being islanded from the grid should a wildfire disable a single transmission line, year-round residents of 15 island communities off the coast of Maine, and communities in the U.S. Virgin Islands.
The DOE offices involved in the Energy Transitions Initiative (ETI) initiative are the Office of Strategic Programs, the Water Power Technologies Office, and the Solar Energy Technologies Office. The participating laboratories are the National Renewable Energy Laboratory (NREL), the Pacific Northwest National Laboratory, the Lawrence Berkeley National Laboratory, and the Sandia National Laboratories.
“The same technical assistance framework NREL developed and used in collaboration with ETI to advance successful energy transitions in Hawaii and the U.S. Virgin Islands can be tailored to ETIPP communities seeking to strengthen their resilience posture and mitigate their risks,” Elizabeth Doris, laboratory program manager for state, local, and tribal governments at NREL, said in a statement.
The community groups involved in the program are the Alaska Center for Energy and Power, the Coastal Studies Institute in North Carolina, the Hawaii Natural Energy Institute, the Island Institute in Maine, and the Renewable Energy Alaska Project.
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.
Calif. CCA group asks governor to take steps to improve grid reliability
September 15, 2020
by Peter Maloney
APPA News
September 15, 2020
The California Community Choice Association (CalCCA) has sent a letter to Gov. Gavin Newsom, asking him to take immediate action to improve the reliability of the state’s electric system.
California is dealing with record-breaking heat, as well as a record setting level of wildfires, which threaten the stability of the state’s power grid.
Earlier this month, the California grid operator called on customers to reduce power consumption during recent heat waves to avoid more drastic rolling outages. In August, the grid operator initiated rolling power outages in response to record heat.
The recent rolling blackouts, “reveal an urgent need to reform the existing resource adequacy rules administered by the California Public Utilities Commission (CPUC) and the CAISO [California Independent System Operator], and focus the CPUC’s integrated resource planning process more rigorously on supply reliability,” Beth Vaughan, executive director of CalCCA, said in the letter.
CalCCA represents 20 Community Choice Aggregators (CCAs) that provide energy to customers in more than 170 California cities and counties. Collectively, CCAs serve about 25% of CAISO’s load.
In the letter, the CalCCA also recommends the governor appoint an Independent Review Panel to consider the results of a root-cause investigation of the conditions that led CAISO to initiate rotating outages on Aug. 14 and 15.
While root causes identified may point to solutions needed to mitigate the risk of repeating similar events, even without certainty regarding root causes, California should begin to take steps to increase reliability through action in the regulatory, legislative, and federal arenas, Vaughan argued.
In the letter, the CalCCA recommended several near-term actions to improve the reliability of California’s grid. Specifically, CalCCA says the CPUC should continue to ensure adequate supplies will be in place for summer 2021 requirements and beyond through the procurement track of the IRP process and review its import restrictions in the context of the recent emergency events.
The CPUC should also use the IRP process to refine needs for the 2024-2026 timeframe. CalCCA supported the CPUC’s 3,300-megawatt (MW) procurement order in 2019 and recommends analysis to identify any incremental near-term procurements beyond the current 3,300 MW order.
CalCCA also recommends using the IRP process in the coming months to “better refine” technical needs, such as capacity, energy, and evening ramp resources, and to establish a fair process to allocate those resources to load serving entities for procurement action.
And the CalCCA recommended that the CPUC should develop a deeper understanding of import resource availability and institutional barriers to securing firm import resources and provide incentives and regulations for behind-the-meter infrastructure to act as supply-side energy and capacity resources.
On the legislative front, CalCCA recommends the state’s legislature should enact AB 3014, which would establish a Central Reliability Authority responsible for planning and coordinating the state’s resource adequacy with CAISO and, where necessary, procuring backstop supply.
CalCCA said it supports the expansion of the federal Investment Tax Credit (ITC) to standalone energy storage resources and the removal of charging restrictions currently limiting the flexibility of battery energy storage to support the state’s ramping and peak needs.
Community choice aggregators have already signed long-term power purchase agreements for an aggregate total of 5,000 MW of new solar, wind, geothermal and energy storage projects and have expanded the use of time-of-use pricing regimes that can help relieve stress on the grid, Vaughan noted, adding that CCAs “are prepared to do more and are committed to working with the Joint Agencies and the investor-owned utilities (IOUs) to support reliable energy service and ensure sufficient in-state renewable integration supply.”
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.