Energy storage in the US is one of the fastest growing markets with a promising future. Over the last five years, the battery-based energy storage system (ESS) capacity has grown more than seven-fold and is pegged to have crossed 10.5 GW by March 2023. The market is dominated by two regional transmission organisations (RTOs), with the California Independent System Operator (CAISO) being the leader in battery storage capacity (over 5 GW) followed by the Electric Reliability Council of Texas (ERCOT) (over 3 GW). By 2025, the country’s ESS capacity is forecasted to reach 30 GW.

The sector’s remarkable growth is driven by the country’s clean energy goals of achieving a carbon-free electricity sector by 2035, which requires integration of huge amounts of intermittent renewable energy. The policy push at the federal and state levels for energy storage has helped boost ESS deployment. Although several challenges continue to stall their development, particularly in terms of huge interconnection backlogs with transmission operators (which was estimated at around 120 GW for standalone battery storage and over 154 GW for hybrid battery storage at the end of 2022), the impending regulatory and market reforms are likely to resolve them to some extent. Recently, the Federal Energy Regulatory Commission (FERC) issued the final rules streamlining the interconnection process for transmission providers, providing greater timing and cost certainty to interconnection customers, and preventing undue discrimination against new sources of power generation.

ESS growth trends

According to US Energy Information Administration (EIA) data, battery ESS grew at a compound annual growth rate (CAGR) of 62.6 per cent between 2018 and 2022. The year 2022 witnessed a record growth of 4,112 MW across 107 utility-scale batteries, 93 per cent of which was added in service territories where an RTO/independent system operator (ISO) manages the grid, and close to 60 per cent were co-located with planned or existing solar capacity.

In terms of the storage applications, the average number of use cases per battery application continued to be constant at 2.4 and over 75 per cent of the installed units reported multiple use cases in 2022. Notably, almost three quarters of the total storage capacity reported frequency regulation as the most often cited use case. This indicates the continuing importance of ancillary services to battery operators. In PJM area, this was associated with 94 per cent of battery capacity. Another commonly cited use case is arbitrage, which refers to batteries getting charged during low price periods and discharged during high prices. Battery operators operating in ERCOT and CAISO together accounted for 95 per cent of all arbitrage use case capacity. This is consistent with the conducive conditions in both markets as they have substantial solar capacity that produces electricity during low-price periods followed by a surge in demand late in the day when prices increase. Ramping and spinning reserve as well as response to excess wind and solar generation were the other two common use cases.

Future ESS growth

From 2023 to 2025, EIA forecasts that another 20.8 GW of utility-scale battery capacity will become operational. Developers have planned more than 23 large-scale battery projects, ranging from 250 MW to 650 MW, to be installed by 2025. Texas (7.9 GW) and California (7.6 GW) will account for more than 75 per cent of this capacity.

Policy developments


Over the last couple of years, the federal government has taken several steps to promote energy storage technologies. Particularly, the Bipartisan Infrastructure Law (BIL) enacted as the Infrastructure Investment and Jobs Act (IIJA) in 2021 has allocated USD505 million to the Department of Energy (DOE) for energy storage demonstration projects for fiscal years 2022 to 2025. BIL also requires DOE to study codes and standards for energy storage systems and establish a grant programme to enhance US battery manufacturing.

Further, the Inflation Reduction Act (IRA) of 2022 created and expanded tax credits for investment in energy storage technology. Specifically, it expanded eligibility for energy credit to include standalone energy storage projects with a minimum capacity of 5 kWh. Previously, eligibility was limited to ESS co-located with qualifying generation facilities. It also created an advanced manufacturing production credit for domestic production and sale of qualifying components, which includes certain battery components and critical minerals.

In November 2022, the DOE Office of Clean Energy Demonstrations (OCED) opened applications for up to USD350 million in BIL funding to develop Long-Duration Energy Storage (LDES) demonstration projects capable of delivering electricity for up to 10-24 hours or longer. DOE will provide financial assistance through cooperative agreements to fund up to 50 per cent of the project cost with the intent to catalyse impactful LDES demonstrations. Funding opportunities are divided into two areas, namely, lithium-based and non-lithium-based ESS. OCED plans to make up to 11 awards between USD9.5 million to USD70 million each in the fall of 2023.

State-level developments

In the US, at least 10 states have set ESS procurement targets including California, Connecticut, Illinois, Oregon, Maine, Massachusetts, Nevada, New Jersey, New York and Virginia. In addition to procurement targets, some states have required utility integrated resource plans (IRPs) to include energy storage. The list includes California, Connecticut, Florida, Massachusetts, Maine, Maryland, Nevada, New Mexico, Oregon, Virginia and Washington among others. Besides federal funding for demonstration projects, some states also provide grants to fund pilots based on advanced technologies. The following are some of the recent state-level developments.

California: The state is a pioneer and set the country’s first procurement target with an initial mandate of 1,325 MW of energy storage by 2020. It is now planning to integrate at least 13,564 MW of lithium-ion battery systems in addition to 1 GW of LDES over the next decade as per CAISO’s latest 2022-23 Transmission Plan. In fact, energy storage capacity under the sensitivity portfolio, which normally becomes the base portfolio in the subsequent year’s transmission plan, includes 28,402 MW of battery storage capacity and 2 GW of LDES. A recent study commissioned by the California Public Utilities Commission (CPUC) estimates the benefits of energy storage at USD1.6 billion annually by 2032. As per the study, by the end of 2021, 2,200 MW/8,900 MWh of storage resources were providing resource adequacy services, and the state has since procured an additional 5,000 MW/20,000 MWh of storage for reliability through 2023.

New Jersey: The state aims to achieve 2 GW installed energy storage by 2030. In October 2022, the New Jersey Board of Public Utilities (NJBPU) released the NJ Energy Storage Incentive Program (NJ SIP) straw proposal with the plan to create two incentive programmes for front-of-meter and behind-the-meter standalone energy storage projects connected to a NJ electric distribution company (EDC). At least 30 per cent of the incentive will be structured as a fixed annual incentive to be paid in dollars per kWh of energy storage capacity subject to up-time performance metrics. The rest of the SIP incentive will have a pay-for-performance structure in which front-of-the-meter (FTM) storage resources will be compensated based on the amount of carbon emissions abated through the operation of the storage device while behind-the-meter (BTM) resources will be compensated based on successful injection of power into the distribution system when called upon by the EDC.

New York: The state aims to achieve 6 GW (previously 3 GW) of storage capacity by 2030 to aid its larger goal of 70 per cent renewable electricity by 2030 and 100 per cent zero-emission electricity by 2040. To achieve this, in January 2023, the New York State Energy Research and Development Authority (NYSERDA) and New York State Department of Public Service (DPS) released an energy storage roadmap. It proposes procuring an additional 4.7 GW of new storage projects across the bulk (large-scale), retail (community, commercial and industrial), and residential energy storage sectors, which, combined with the 1.3 GW of existing energy storage already under contract with the state, will allow it to achieve its 2030 goal.

Earlier in September 2022, New York announced USD16.6 million in awards for five LDES projects. A further USD17 million in funding is available through a competitive bidding process for initiatives that enhance the development and demonstration of scalable innovative, long-term energy storage technologies, such as hydrogen. These awards and new funding are being made available through the NYSERDA-administered Renewable Optimisation and Energy Storage Innovation Program.

Other states: Connecticut has a procurement target of 1 GW by 2030 with an interim target of 300 MW by 2024 and 650 MW by 2027. Of the total, 580 MW must be distribution-connected. 

Nevada has a target of 1 GW by 2030 while Virginia aims to achieve 3,100 MW of storage capacity by 2035. Maine set its goal in 2021 to achieve 400 MW of storage by 2030 with an interim target of 300 MW by 2025. In Oregon, Portland General Electric (PGE) recently announced the procurement of 400 MW of new ESS projects to be in service by 2025 and Pacific Power plans to add more than 8 GW over the next two decades.

In 2021, the Illinois Climate and Equitable Jobs Act directed the Illinois Commerce Commission to fix storage procurement targets for all utilities serving over 2,00,000 customers to achieve by 2032. Massachusetts set its target in 2018 through the Act to Advance Clean energy at 1,000 MWh by 2025. The state has provided USD20 million in grant funding to 26 storage projects aggregating 32 MW/83 MWh through the Advancing Commonwealth Energy Storage (ACES) programme to demonstrate nine use cases by 2024.

Regulatory developments

On its part, FERC issued orders in 2018 and 2019 (Order No. 841 and Order No. 841–A) to remove barriers to participation of energy storage technologies in the capacity, energy and ancillary services markets operated by RTOs/ISOs through an appropriate participation model for energy storage resources (ESRs). It also called for RTOs to allow self-management of state-of-charge (SOC), which is the amount of energy available in a battery relative to its capacity. Establishing an ESR participation model involves tariff revisions that consist of market rules which, recognising the physical and operational characteristics of the resource, facilitate their participation in the RTO/ISO markets. All the RTOs/ISOs under FERC jurisdiction (which excludes ERCOT) have implemented Order 841 and have in place some form of participation model for ESRs.

Recently, on July 27, 2023, FERC issued new interconnection rules to address the issue of growing backlogs of interconnection requests with transmission providers. This follows the notice of proposed rulemaking (NOPR) released last year. The rules will take effect 60 days after publication in the federal register while compliance filings are due in 90 days.

Specifically, FERC’s final rule includes several key areas of reforms including institution of a ‘first-ready, first-served’ cluster study process based on readiness rather than order of entry into the queue, which is the basis of the ‘first-come, first-served’ study process, with increased financial commitments for interconnection customers, to improve the efficiency of the interconnection process and minimise delays; imposition of firm deadlines and penalties if transmission providers fail to complete their interconnection studies on time,  consideration of advanced transmission technologies in the interconnection study process; and an update of modelling and performance requirements for inverter-based resources to ensure continued system reliability.

The following are some of the recent developments at the RTO/ISO level.

CAISO: According to a special report on battery storage released by CAISO in July 2023, over half of the 5 GW of installed capacity (as of May 2023, grown from only 500 MW in 2020) is physically paired with renewables either sharing a point of interconnection under the co-located model or as a single hybrid resource. In fact, in 2022, batteries accounted for a significant portion of load during peak solar hours, which has helped reduce the need to curtail or export surplus power at low prices. Batteries also provided over half of CAISO’s regulation up and down ancillary services requirements in the day-ahead and real-time markets. Net revenue for batteries increased to USD103 per kW-year in 2022 from about USD73 per kW-year in 2021.

Storage resources participate under the non-generator resource (NGR) model in the CAISO market. NGRs operate as generation or load and bid into the market using a single supply curve with prices for negative capacity (charging) and positive capacity (discharging). In November 2022, FERC approved market rule changes that preclude batteries from receiving bid cost recovery (BCR) (which is equal to the difference between the sum of all the unit’s accepted bids and total market revenues earned during a day) in situations where they are uneconomically dispatched by the market software to maintain a sufficient SOC to fulfil ancillary service awards. CAISO’s Department of Market Monitoring (DMM) estimates that USD8.4 million of the USD30.5 million BCR received by batteries during 2022 will be rescinded in future settlements due to FERC tariff revision approval.

ISO-NE: In September 2022, FERC approved a change to ISO New England’s (ISO-NE) tariff, which allows battery storage facilities charged by renewables better access to the wholesale electricity markets. This revision opened up an existing participation model, Continuous Storage Facility (CSF), to storage facilities that charge exclusively from co-located generation from October 1, 2022. Prior to this, storage facilities seeking to participate under the CSF model had to be capable of injecting as well as consuming electricity from the grid. The tariff change will also improve ISO-NE’s ability to monitor and dispatch these facilities compared to other market participation options for inject-only storage.

 New York: New York ISO (NYISO) tariffs treat ESRs as suppliers in the wholesale electric markets. NYISO is in the process of developing a hybrid storage resource (HSR) model, which will expand opportunities for storage resources to aggregate with other generators behind the same point of interconnection. All generators in a HSR will collectively participate in the wholesale markets as a single resource. Earlier in March 2023, NYISO had announced a project to assess whether a process for evaluating an energy storage project as a regulated transmission asset is needed to complement the existing wholesale market rules for ESRs. As part of the project, NYISO will consider and discuss incorporating storage as transmission into NYISO planning processes in addition to considering rules and ways for operating storage as a transmission asset to address identified reliability issues.

MISO In compliance with Order 841, in September 2022, the Midcontinent Independent System Operator (MISO) announced the inclusion of the ESR model in its portfolio. MISO had requested that the compliance deadline be pushed back until 2025, but FERC denied the request. The model includes batteries, pumped storage and compressed air energy storage. The model’s implementation enables the resources to participate in MISO’s Energy and Operating Reserves Markets as supply and demand. According to MISO’s generator interconnection queue, more than 150 energy storage projects totalling approximately 13,300 MW of capacity are in various stages of development. It is seeking such projects to assist in reducing peak demand, managing congestion, and providing backup power in the event of major generator outages.

PJM Interconnection: In July 2023, PJM initiated a new interconnection process to address the significant backlog of planned renewable and battery projects. This is in line with the FERC-approved interconnection process reforms in November 2022. The new process would study over 260 GW of projects within the next three years. Over 95 per cent of the projects seeking grid connection are related to renewables, batteries or a combination of both. PJM plans to transition from a “first-come, first-served” queue approach to a “first-ready, first-served” cycle method (similar to the FERC proposal), aiming to reduce the number of speculative projects that have contributed to the backlog. Developers in the transition phase now have a 60-day window to submit readiness requirements. PJM plans to update its models with qualifying generators in September 2023 and begin processing projects with minimal or no system impacts that qualify for a fast-lane process. 

SPP: In May 2023, FERC granted approval to the Southwest Power Pool (SPP) for its proposal to enable ESRs to serve as transmission-only assets (SATOAs) in certain circumstances. This was in response to SPP’s proposal (ER22-2344) filed in July 2022. The proposal establishes that SATOAs will have limited participation in the SPP-operated energy market and will be permitted to charge and discharge solely to address specific transmission needs within the SPP system. FERC concluded that under these circumstances, SATOAs should be categorised as transmission assets, and their costs could be appropriately recovered through transmission rates.

Challenges and the way forward

Despite rapid growth in energy storage capacity, the regulatory environment in terms of market rules and permitting processes can pose challenges to energy storage deployment. There is a need for harmonisation of market rules and regulations for energy storage as transmission or generation to encourage investment in utility-scale storage projects. Variation in rules and regulations across regions also adds to the challenge. Permitting and other approvals also require substantial investment and involve lengthy processes. A recent report by the Lawrence Berkeley National Laboratory (LBNL) highlights that the transmission interconnection costs have doubled for both PJM and MISO in recent years and proposed energy storage projects in their interconnection queues face significantly higher costs than natural gas generators. These issues have been broadly acknowledged and interconnection reforms as well as changes to market rules are on the cards.

Another area that requires attention is the revision of existing codes and standards as they do not fully address energy storage technologies. There should be a focus on ensuring safety of storage systems from fire hazards and other operational risks in addition to cyberattacks. Domestic manufacturing bases also need to be ramped up to reduce reliance on foreign suppliers. Federal and state agencies need to put in place clear and consistent policies for utility-scale battery reuse and end-of-life recycling.

Notwithstanding the challenges, the medium- to long-term outlook for the US energy storage sector remains positive, though there may be some short-term delays in commissioning of ongoing projects. Strong federal and state support will boost future deployments. Importantly, regulators recognise the value of the multiple services that energy storage is capable of providing to maintain system frequency and stability, which is critical given the huge expected renewable penetration to meet the clean energy goals. Harmonising regulatory treatment to ESR and resolving the issue of interconnection process through implementation of recent FERC rules will help the sector take a big leap forward given the huge proposed investments in renewable and storage projects awaiting grid access.