SMUD Launches Virtual Power Plant Program With Swell Energy
January 4, 2023
by Peter Maloney
APPA News
January 4, 2023
The Sacramento Municipal Utility District (SMUD) in late December announced an agreement with Swell Energy that would give the California public power utility the ability to tap into its customers’ energy storage devices to create a “virtual power plant.”
Under the agreement, Swell Energy will act as the aggregator for the My Energy Optimizer Partner+ program. The initial effort of the program would provide SMUD with 20 megawatt hours (MWh) and 10 megawatts (MW) of renewable capacity by recruiting, installing and aggregating capacity from customer battery storage systems in its service territory. The program has the opportunity to scale to 54 MWh and 27 MW over the term of the partnership, SMUD said.
The program enables customers to operate their energy storage systems alongside many others to aggregate and dispatch renewable energy sources to benefit their communities.
SMUD said it currently has about 600 customer-sited energy storage systems with another 400 systems in the interconnection process and thousands more projected over the next several years.
SMUD plans to begin enrollment in the My Energy Optimizer Partner+ program in the first quarter and begin operations in April. Enrollment is open to both new and existing solar and storage customers with contract capability is based on 2-hour deliverable capacity.
Participating customers will receive both upfront and ongoing compensation, or GridRevenue, based on the capacity of their solar and energy storage systems.
Utilities from Hawaii to Vermont are exploring virtual power plants, including Holy Cross Energy, a cooperative utility in Glenwood Springs, Colorado, and Con Edison in New York, which is working with SunPower Corp. on a pilot program to offer solar power systems with battery storage to more than 300 New York homeowners. Last June, California community choice aggregator Marin Clean Energy unveiled a virtual power plant program that is expected to begin in 2025.
Utility Scale Battery Storage Growth Tracks Renewables, But is Even Faster: EIA
December 16, 2022
by Peter Maloney
APPA News
December 16, 2022
Utility-scale battery storage capacity is poised for explosive growth in the United States as it tracks and outpaces renewable growth, especially in California and Texas, according to a report released this week by the Department of Energy’s Energy Information Administration (EIA).
Over the next three years, U.S. utility-scale battery storage capacity could reach 30 GW by year-end 2025, from 7.8 GW as of October 2022, according to the EIA’s latest Preliminary Monthly Electric Generator Inventory, which is based on data reported to the agency by developers and power plant owners.
Battery storage in the United States was “negligible” prior to 2020, but began growing rapidly, the EIA said. The growth of battery storage capacity tracks the rising pace of wind and solar installations but is even outpacing the early growth of utility-scale solar capacity, which grew from less than 1 GW in 2010 to 13.7 GW in 2015, according to EIA data.
U.S. battery storage capacity was 1.5 GW in 2020 and by year end it could reach 9.2 GW with another 20.8 GW expected to come online between 2023 and 2025. More than 75 percent of the 20.8 GW in development is in Texas and California, which account for 7.9 GW and 7.6 GW, respectively, of the expected additions by 2025. Both of those states are also leaders in renewable resources.
Texas has 37.2 GW of wind capacity, more than in any other state, and developers expect to add an additional 5.3 GW over the next three years, the EIA said. Texas also has 10.5 GW of utility-scale solar capacity and developers plan to install another 20.4 GW between 2023 and 2025 in the Lone Star state.
California has more utility-scale solar capacity than in any other state with 16.8 GW and another 7.7 GW expected to be added between 2023 and 2025.
As more battery capacity becomes available to the U.S. grid, battery storage projects are also becoming larger, the EIA noted. Before 2020, the largest U.S. battery storage project was 40 MW. The 250-megawatt (MW) Gateway Energy Storage System in California, which began operating in 2020, marked the beginning of large-scale battery storage installation, the EIA said.
Now, the 409-MW Manatee Energy Storage facility in Florida is the largest operating storage project in the country. Developers have scheduled more than 23 large-scale battery projects, ranging from 250 MW to 650 MW, to be deployed by 2025, according to EIA data.
Quidnet Awarded $10 Million to Fund CPS Energy Pumped Hydro Storage Project
December 13, 2022
by Peter Maloney
APPA News
December 13, 2022
Quidnet Energy has been selected to receive $10 million in funding from the Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E) for a pumped hydro storage project the Houston company is developing for CPS Energy, the public power utility serving San Antonio, Texas.
Quidnet plans to use the ARPA-E funding to scale up its Geomechanical Pumped Storage (GPS) project to a 1-megawatt (MW), 10-megawatt hour (MWh) commercial system.
CPS Energy signed a 15-year capacity tolling agreement with Quidnet in March. The energy storage project could eventually be scaled up to as much as 15 MW.
CPS Energy said the project will support its “Flexible Path” Resource Plan to reduce net emissions by 80 percent by 2040.
Quidnet’s geomechanical technology stores energy by using renewable resources to pressurize water and store it underground in “storage lens” between layers of rock. The storage lens technology has been successfully demonstrated using different geologies across the United States, the DOE said.
Quidnet, which was co-founded by Microsoft co-founder Bill Gates, hopes to move its GPS technology from pilot scale to commercial scale by increasing the size of the storage lens, improving lens sealing, and commissioning the first grid-connected system. The company said the commercialization of the technology is aided by the fact that it uses existing drilling and hydropower machinery supply chains.
The funding for the GPS project falls under ARPA-E’s Seeding Critical Advances for Leading Energy technologies with Untapped Potential (SCALEUP) program, which provides further funding to previous ARPA-E teams that have been determined to be feasible for widespread deployment and commercialization.
Quidnet said its objective is to lower the cost of long-duration energy storage, that is, energy storage capable of providing 10 or more hours of electrical output, by 50 to 75 percent in an effort to make intermittent renewable energy sources more reliable and cost effective.
Department of Energy Makes Nearly $350 Million Available for Long-Duration Energy Storage
November 17, 2022
by Paul Ciampoli
APPA News Director
November 17, 2022
The U.S. Department of Energy (DOE) recently announced nearly $350 million for emerging Long-Duration Energy Storage (LDES) demonstration projects.
The LDES Demonstrations Program will be managed by DOE’s Office of Clean Energy Demonstrations (OCED) and will fund nearly $350 million for up to 11 demonstration projects — projects that will contribute to the Department-wide goal of reducing the cost of grid-scale energy storage by 90% within the decade. DOE will fund up to 50% of the cost of each project.
The program aims to fund projects that will overcome the technical and institutional barriers that exist for full-scale deployment of LDES systems by focusing on a range of different technology types for a diverse set of regions.
Letters of Intent are due by December 15, 2022, and full applications are due by March 3, 2023. Additional funding opportunities may follow this announcement to validate and accelerate commercialization of LDES technologies.
In October, DOE issued a $30 million Lab Call Announcement for Long-Duration Energy Storage Demonstrations. Remaining funding for LDES programs will be covered at a later date.
For more information on DOE’s Long-Duration Storage Shot initiative, click here.
California Energy Commission Grant Will Fund Long Duration Storage for Calif. Tribe
November 14, 2022
by Peter Maloney
APPA News
November 14, 2022
The California Energy Commission (CEC) earlier this month made a $31 million grant to fund a long duration energy storage system for the Viejas Tribe of Kumeyaay Indians in Southern California.
The grant is the first award under California’s $140 million Long-Duration Energy Storage Program, which is part of the state’s efforts to fight climate change and to achieve 100 percent clean electricity by 2045.
The CEC said the 60-megawatt-hour (MWh) project is one of the first of its kind in the country and will provide renewable backup power to the Viejas community in the event of local outages and provide the opportunity for the tribe to shift electricity use away from California’s electric grid during calls for conservation.
The CEC awarded the grant to Indian Energy LLC, a privately held Native American-owned developer that is building a microgrid project on the tribe’s behalf.
“This solar microgrid project will enable us to create a reliable and sustainable source of clean energy for our gaming, hospitality, and retail operations going forward,” John Christman, chairman of the Viejas Band of Kumeyaay Indians, said in a statement.
The Viejas Band is one of 12 bands of the Kumeyaay Indian Nation that lives on a 1,600-acre reservation in the Viejas Valley, near Alpine in San Diego County, where the tribe owns and operates the Viejas Casino and Resort.
The microgrid system is designed to deliver power to the casino and resort. The energy storage system will connect with an existing, onsite 15-MW solar power installation. Eos Energy Enterprises is supplying a 35-MWh, zinc-based flow battery to the project. Invinity Energy Systems is supplying a 10-MWh vanadium redox flow battery. The energy storage system will have the potential to discharge for up to 10 hours.
The remaining 15 MWh will also be non-lithium ion and will provided by the tribe at a later date, CEC spokeswoman Lindsay Buckley said via email. The initial 45 MWh are scheduled to enter service by summer 2023, and we expect the full 60 MWh to be operational by the summer of 2024.”
Flow batteries use electrolytes moving through tanks to produce electricity. They are rechargeable and do not degrade. And, because they do not use lithium ion, they avoid the potential first hazards associated with those batteries.
Sunrun to Build and Operate Puerto Rico’s First Virtual Power Plant
November 8, 2022
by Paul Ciampoli
APPA News Director
November 8, 2022
Sunrun has been selected by Puerto Rico’s electric utility provider to develop a 17-megawatt virtual power plant (VPP), the first distributed large-scale storage program on the island.
The Governing Board of the Puerto Rico Electric Power Authority, a public power utility, approved the terms of the agreement on October 26, 2022. The agreement is subject to regulatory sign-off by the Puerto Rico Energy Bureau and the Fiscal Oversight Management Board.
Sunrun will spend the next year enrolling customers into the program and begin networked dispatches in 2024.
“Customers will benefit from the cost savings of on-site energy generation and backup power and will also be compensated in exchange for strategically sharing their stored energy with Puerto Rico’s power grid, creating a shared clean energy economy,” it said.
Batteries enrolled in the VPP will continue maintaining adequate backup reserves to power through potential grid outages at participants’ homes. All customers with batteries are also eligible to enroll and can opt out at any point during the 10-year program.
In 2019, two years after Hurricane Maria dismantled the island’s electric grid, the Puerto Rico Energy Public Policy Act was passed by the Legislature to set the parameters for a forward-looking energy system that maximizes distributed generation.
The Puerto Rico Energy Bureau (PREB) determined that VPPs were key to achieving the legislation’s goals of building a resilient and robust energy system and meeting Puerto Rico’s renewable portfolio standards, Sunrun said.
Burbank Water and Power Enters Agreement for First Utility-Scale Battery Storage Project
November 8, 2022
by Paul Ciampoli
APPA News Director
November 8, 2022
ESS Inc. and California public power utility Burbank Water and Power (BWP) have entered into an agreement for ESS to deliver BWP’s first utility-scale battery storage project.
Under the agreement, a 75 kilowatt (kW)/500 kilowatt hour kWh ESS “Energy Warehouse” will be installed and connected to a 265 kW solar array on BWP’s EcoCampus.
The iron flow battery will support the increased use of renewable power and allow excess renewable energy to be stored and used as baseload energy for Burbank, improving the resilience and reliability of the grid, ESS said on Nov. 4.
“BWP is already using small-scale battery technology at our substations, but we see the value in adding considerably more storage to the network. This initiative will be the largest battery installed in Burbank, providing enough renewable power for 300 homes annually,” said Mandip Samra, Assistant General Manager for Power Supply at BWP, in a statement. “The project is a big step forward to help meet our goal of having a greenhouse gas-free power supply by 2040 and providing energy storage for Burbank now and for decades to come.”
The storage system is expected to be installed in Burbank by December 2023.
In September 2022, another California public power utility, SMUD, and ESS Inc. announced an agreement to provide up to 200 megawatts/2 gigawatt-hours of long duration energy storage that will be provided by ESS.
Salt River Project Contracts for Two Battery Storage Projects Totaling 340 MW
October 31, 2022
by Peter Maloney
APPA News
October 31, 2022
Salt River Project (SRP) in Arizona has signed contracts with Plus Power for two battery storage systems totaling 340 megawatts (MW) that are expected to be online early in the summer of 2024.
The Sierra Estrella battery project will be a 250-MW, four-hour battery storage system in Avondale. The Superstition project is designed as a 90-MW, four-hour battery storage system in Gilbert.
SRP said it would have dispatch control of the storage systems, which will give the public power utility the ability to decide at what point each day it will deploy the energy output from each system onto its grid. SRP said deployment would typically occur during times of peak energy demand, usually in the early evening when demand for electric power is high and renewable resources are not available.
“These early deployments will help both SRP and the industry gain experience with this technology, which will play a major role in reducing carbon emissions,” Kelly Barr, SRP’s chief strategy, corporate services and sustainability executive, said in a statement.
SRP selected the two grid-charged battery projects from its most recent all-source request for proposals process. Both projects will be owned and operated by a subsidiary of Houston-based Plus Power.
SRP said the two planned projects push its total commitment to battery storage to 800 MW by 2024 and represent over 10 percent of the utility’s anticipated peak electric demand in 2024.
SRP is also developing the Sonoran Energy Center, an approximately 250-MW system with the solar array charging a 1,000-megawatt hour energy storage system, that is sited in Little Rainbow Valley, south of Buckeye. SRP has also contracted for the 88-MW Storey solar and battery storage project near Coolidge and plans to add a battery to the Saint Solar project, which is also near Coolidge. All three projects are scheduled to enter service in 2023.
In 2021, SRP brought a 25-MW battery storage facility at its Bolster substation in Peoria online.
Recent California Energy Storage Battery Fire Draws Renewed Attention to Storage Safety Issues
October 17, 2022
by Paul Ciampoli
APPA News Director
October 17, 2022
A recent fire at a battery storage facility in California is bringing fresh attention to safety issues tied to energy storage as the technology grows in deployment across the U.S.
The fire occurred in September 2022 at Pacific Gas & Electric’s (PG&E) Moss Landing battery storage facility in California. The fire was isolated to a single battery pack at the facility, according to the County of Monterey, Calif.
PG&E in April announced the commissioning of its 182.5-megawatt (MW) Tesla Megapack battery energy storage system – known as the Elkhorn Battery – located at its Moss Landing electric substation in Monterey County.
The Elkhorn Battery system was designed, constructed, and is maintained by both PG&E and Tesla, and is owned and operated by PG&E.
An editorial in California’s Santa Cruz Sentinel newspaper said that while the move to energy storage will continue, the Moss Landing fire “was also a reminder that battery blazes are becoming increasingly common and destructive – and safety measures, including fire drills, for residents around storage facilities will have to be put in place and widely disseminated.”
Arizona Also Experiences Incidents With Storage Fires
California is not the only state where energy storage facilities have experienced fires.
In neighboring Arizona, investor-owned Arizona Public Service (APS) in 2020 released the findings of an investigation into an incident that occurred at an APS battery storage site in 2019.
Around 5 p.m. on April 19, 2019, there were reports of smoke from the building housing the energy storage system at APS’s McMicken site in Surprise, Ariz.
Hazardous Material units and first responders arrived on scene to secure the area. Approximately three hours after the reports of smoke and shortly after the door was opened, the site experienced a catastrophic failure. Injured first responders were transported to area hospitals.
An investigation led by APS, with first-responder representatives, the system integrator, manufacturers and third-party engineering and safety experts, was conducted to determine the cause of the incident and identify lessons that can be applied to future battery energy storage systems.
The investigation involved a number of key stakeholders, and APS commissioned several forensic experts and nationally recognized research institutions. Once the investigative work was completed, APS chose DNV GL to combine various forensic and expert inputs into the single, consolidated report.
Among other things, the report said that the suspected fire “was actually an extensive cascading thermal runaway event, initiated by an internal cell failure within one battery cell in the BESS [battery energy storage system].”
In August 2019, an Arizona utility regulator raised questions about the safety of certain lithium-ion batteries, following fires at APS battery storage facilities.
In a letter to her fellow commissioners, commission staff and other interested parties, Commissioner Sandra Kennedy, of the Arizona Corporation Commission, said the types of lithium ion chemistries used at those facilities “are not prudent and create unacceptable risks.”
Along with the April 19 fire, Kennedy’s letter also cited a November 2012 fire at an APS storage facility at its Elden substation.
More recently, a fire broke out an energy storage facility in Chandler, Ariz., in April 2022. The incident occurred at the Dorman battery storage system, a 10 MW, 40 megawatt-hour stand-alone battery storage system in Chandler. The BESS is interconnected with and provides service to the Salt River Project. It is owned by AES Corp.
The investigation “into what happened at Chandler is still underway. We expect a determination in the coming weeks,” said AES spokesperson Gail Chalef on Sept. 26.
Standards for Energy Storage Systems
A key player in addressing concerns about energy storage technology safety issues is the National Fire Protection Association (NFPA).
“NFPA is keeping pace with the surge in energy storage and solar technology by undertaking initiatives including training, standards development, and research so that various stakeholders can safely embrace renewable energy sources and respond if potential new hazards arise,” it notes on its website.
NFPA’s safety standard, NFPA 855, “provides insight into mitigating risks and helping to ensure all installations are performed appropriately, taking into account vital life safety considerations,” NFPA states. The standard “offers comprehensive criteria for the fire protection of ESS installations based on the technology used in ESS, the setting where the technology is being installed, the size and separation of ESS installations, and the fire suppression and control systems in place.”
And cities are proactively taking steps to address storage-related safety issues. The New York City Fire Department in 2019 adopted a final rule related to energy storage systems.
The Fire Department adopted the rule to establish standards, requirements and procedures for the design, installation, operation and maintenance of outdoor stationary storage battery systems that use various types of new energy storage technologies, including lithium-ion, flow, nickel-cadmium and nickel metal hydride batteries. The rule does not govern indoor battery installations.
Among other things, the rule sought to address fire safety concerns associated with new battery technologies by setting testing standards and establishing an equipment approval process for manufacturers.
“Establishing testing standards, and in particular, requiring full-scale testing of battery system components and pre-engineered products, will enable manufacturers to identify fire safety issues and eliminate them or engineer mitigating measures in the design,” the Fire Department said. “The evaluation of the performance of battery system components or products in this manner will also allow the Fire Department to eliminate or expedite its approval process for specific installations,” it said.
Virginia County Holds Off on Battery Storage Project Decision
Concerns over battery storage fires and safety prompted the James City County Board of Supervisors in Virginia to recently defer a decision on a proposed battery storage facility in the county.
At issue is a 22.35-MW lithium ion battery storage project proposed by Calvert Energy LLC.
At the Oct. 11, 2022 board meeting, several members of the James City County Board of Supervisors raised questions related to fire and safety issues involving the project.
Brian Quinlan, President and CEO of Calvert Energy, noted the NFPA standard for batteries “and this system is designed to meet or exceed the containment requirements for battery storage, which basically means that the fire is contained within the container, so it won’t burn through the container walls.”
The Calvert Energy project also includes blowout panels, he noted. This means that “gases won’t build up and cause an explosion.” In addition, there is also dry chemical fire prevention “built into the unit itself as well, so there’s a number of different levels of fire protection built into the system.”
The board voted to defer a decision on the project to its Nov. 8 meeting.
RFQ in Massachusetts Addresses Storage Fire Training
The City of Boston in late 2021 issued a request for qualifications (RFQ) to provide comprehensive engineering, design, and construction services in connection with the installation of a rooftop photovoltaic (PV) array, a commercial-scale battery energy storage system (BESS) and a residential-scale battery energy storage system at the Boston Fire Department’s Fire Training Academy on Moon Island, in Quincy, Mass.
The RFQ said that at a minimum the BESS “shall meet and fully satisfy the Standard for the Installation of Stationary Energy Storage Systems established by the National Fire Protection Association (NFPA 855), including any underlying standard adopted by and incorporated into NFPA 855, such as UL 9540A.”
The RFQ notes that the project is intended to complement the Boston Fire Department’s curriculum for firefighting trainees: in particular, to provide those trainees with an opportunity to become familiar with working examples of PV and BESS technologies.
Joseph LaRusso, Energy Efficiency and Distributed Resources Finance Manager in the City of Boston’s Environment Department, told Public Power Current that the city has completed evaluating the qualifications statements that were submitted in response to the RFQ, and the city is currently negotiating the terms of an energy services agreement (ESA) with the firm that submitted the highest-ranked proposal.
The city plans to release the name of that company once the terms of the ESA have been successfully negotiated and the contract is awarded.
Report Finds Solar with Storage Can Provide Reliable Residential Backup Power
October 4, 2022
by Peter Maloney
APPA News
October 4, 2022
Behind-the-meter solar-plus-energy storage systems (PVESS) can generally provide at least minimum levels of backup power during power interruptions, according to a new report by Lawrence Berkeley National Laboratory (LBNL).
The report, Evaluating the Capabilities of Behind-the-Meter Solar-plus-Storage for Providing Backup Power during Long-Duration Power Interruptions, found that backup performance of PVESS can vary depending on a variety of circumstances.
The best performance observed in the report, which included both simulations and historical analysis of how PVESS would have performed during a sample of actual historical events, was for residential buildings. If heating and cooling loads are excluded from those residences, a small PVESS with 10 kilowatt hours (kWh) of storage, the lower end of sizes currently in the market, can fully meet basic backup power needs over a three-day outage in virtually all U.S. counties and in any month of the year, the report found.
If critical loads include heating and cooling, a 10-kWh PVESS would meet 86 percent of critical load on average across all counties and months, while a 30-kWh PVESS, the upper end of sizes currently in the market, would meet 96 percent of critical load.
The report’s authors noted, however, that the results showed considerable performance within individual regions, based on variations in building stock. Performance declines for higher-usage homes but, more significantly, performance is affected by heating technology, building infiltration or “leakiness,” air-conditioner efficiency, and temperature set-points.
The single biggest impediment to backup performance is the presence of electric space heating, which is currently mostly electric resistance, and is most prevalent in the Southeast and the Pacific Northwest, the report said.
The authors also noted that backup performance for homes with electric heat or high cooling loads is quite sensitive to weather variability. For example, in counties with high penetration of electric heat, between 53 percent and 96 percent of critical load is served during winter months, depending on which specific day the outage begins. A similar but less dramatic was observed for homes with high cooling loads, the authors added.
In terms of duration, the report found that backup performance is fairly insensitive to outages lasting longer than one day. In general, backup performance declines as outage duration increases, though the effect is relatively modest, given the ability of solar panels to recharge batteries each day, the authors said.
For a PVESS with 30-kWh of storage and critical loads that include heating and cooling, backup performance drops from a population-weighted average of 100 percent of critical load served for a one-day outage to 92 percent for a 10-day outage, the report found.
In seven of the 10 historical outage events analyzed, the majority of homes would have been able to maintain critical loads with heating and cooling, using a PVESS with 30 kWh of storage, the report said. However, the authors noted that there was considerable variability among the five hurricane events analyzed, which was driven by differences in solar insolation levels.
The lowest performing event was Hurricane Florence, where almost no solar generation occurred over the first three days of the roughly eight-day outage due to cloud cover. For the two winter storms analyzed, all critical load was served in the median case, but a sizeable fraction of customers—those with electric heating—saw much lower performance, the report said.
The major constraint to backup performance for commercial buildings were roof area constraints on solar system sizing, the report said. “Providing full-building backup for a multi-day outage would require significantly larger systems than what is typically observed in the market today, for systems installed primarily for other purposes,” the authors said.
LBNL said the report is the first in a series it plans to do in collaboration with the National Renewable Energy Laboratory on the use of PVESS for backup power. The report’s authors plan to host a webinar summarizing key findings of the new report on Oct. 6.