This is an extract from a recent report “Charging Up: The State of Utility-Scale Electricity Storage in the United States” by Resources for the Future.
As the electricity sector relies more on variable energy sources like wind and solar, grid-connected energy storage will become increasingly important to support reliable electricity supply. Storage can transfer electricity generated during hours when renewable energy is plentiful to meet demand at other times of the day. Grid-scale storage specifically can also provide key grid services, such as reserve power, frequency response, and flexible ramping, to support grid stability. As the needs of the grid evolve, storage can provide effective solutions, but it does not always fit neatly into the market designs and operating practices in the electricity sector. It remains unclear what types of market designs and incentives are needed to elicit optimal storage deployment without overprocuring storage relative to more efficient options. This extract focuses on policies in place and under discussion that could have an impact on grid-scale storage deployment and the market structures that affect storage operations and incentives.
Policies Supporting Storage
Because storage is an emergent technology, state and federal policies play a critical role in supporting its deployment across the United States. Some policies incentivize storage explicitly, while others alter the electricity generation landscape in ways that can enhance the incentives for storage developers. Policy levers can be categorized in several different ways.
Policies that reduce fossil fuel generation could include renewable or clean energy standards, carbon emissions cap-and-trade programs, and emissions standards for power plants. These policies tend to make fossil generators less attractive than cleaner sources and therefore reduce fossil fuel generation and increase fossil generator retirements. To date, most retirements have been concentrated among coal plants, but as standards continue to tighten or cap-and-trade programs become more ambitious, gas plants may be more affected. As zero-emissions energy continues to grow, supported by these standards or emissions caps, energy storage may become more prevalent as its competition shifts from traditional fossil resources, like gas and coal, to more expensive clean firm resources that meet the standards, like advanced nuclear, hydrogen, or geothermal.
Energy storage may also take advantage of tax credits or other incentives for clean energy. The clean energy investment tax credits included in the Inflation Reduction Act (IRA) can be leveraged by stand-alone energy storage providers as well as by storage that is colocated with renewables, and in the case of the latter, the renewables remain eligible for the IRA production tax credit. While offering credits only for storage paired with renewables offers greater certainty over the emissions intensity of stored energy, it may limit value delivered to the grid by skewing toward sites where renewables can be located rather than those with the greatest grid need.
Policies may also be implemented in the future that directly incentivize clean firm generation. These incentives would not be available to wind, solar, or even shortduration batteries but would specifically target resources that could help meet reliability needs, like advanced nuclear, hydrogen, geothermal, or long-duration energy storage. The clean hydrogen production tax credit (45V), established by the IRA, is an example of an incentive designed to expand these kinds of resources. Future policies could specifically subsidize resources that are likely to be available when supply of variable resources is low or demand is particularly high. It is not clear how well energy storage would compete among a growing pool of new technologies, but specifically incentivizing clean firm resources in a technology-neutral way could offer greater financial opportunities for long-duration storage, perhaps paired with renewable resources.
Finally, the most direct support for energy storage is through procurement mandates. Table 1 lists states that have renewable portfolio standards and storage procurement mandates with associated deadlines. Renewable portfolio or clean energy standards require a certain amount of energy to come from approved renewable or clean sources (the definition of which can vary by state and may or may not include storage). Storage procurement rules generally require utilities to purchase a specific amount of storage capacity. These rules can be set by state legislatures or public utility commissions.
Policies that explicitly mandate storage can help kick-start development of the technology, but they do not typically aim to identify the optimal amount of storage deployment. Instead, they generally set relatively modest targets that require utilities and power providers to do the initial work to integrate storage providers into their planning and operating processes. To encourage the optimal amount of storage in a system, regions rely on either centralized planning or market mechanisms.
Competitive Market Rules for Storage
Because electricity market rules are set independently by region, independent system operators can take specific actions that can either obstruct or enhance the opportunity for energy storage owner/operators to collect revenues. System operators define storage eligibility for different market products, interconnection processes, and bidding or accreditation rules for storage owner/operators that affect revenue potential. However, rules in all markets (except Texas) are subject to FERC approval, so operator discretion is bounded. For instance, FERC Order 841 requires system operators to establish rules and regulations to better integrate energy storage providers in energy, capacity, and ancillary service markets. There are competitive market rules for storage and how they might accelerate or constrain grid-scale storage development, as well as the different ways that ISOs can affect opportunities for gridscale energy storage.
Interconnection: The first interaction between an energy supplier and an RTO is through an interconnection request. New suppliers that want to connect to the grid must make a specific request to the RTO and wait for relevant transmission owners to assess their impact on the grid. Energy storage has a slightly more complex relationship with interconnection processes, not only because it offers to supply electricity that could affect grid stability, but also because storage devices, particularly stand-alone storage, act as demand for grid electricity when charging.
In PJM, energy storage faces significant challenges with interconnection. Unlike in other jurisdictions, storage providers in PJM are not permitted to submit their own operating parameters when making an interconnection request, such as committing not to draw power during peak demand periods, when prices are high. As a result, system operators need to assume that storage owner/operators may act as demand during times of system strain, thereby exacerbating grid congestion. Of course, storage providers may be able to deliver additional supply during these times, having the opposite effect and relieving congestion. FERC Order 2023 attempted to improve clarity around interconnection rules for energy storage, but PJM has lagged in addressing this issue, potentially overestimating the risk of energy storage providers overloading the grid.
ERCOT’s interconnection process, in contrast, experiences fewer delays because of its “connect and manage” approach to new generation, which allows generators to connect without paying for costly network upgrades but allows ERCOT to manage its supply as needed to maintain grid stability. For energy storage, this can affect an operator’s charging and discharging preferences and revenue. Overall, facilities can come online faster in ERCOT, but developers may require more time to understand which sites of interconnection have the greatest potential value. The ERCOT interconnection process takes approximately 3.5 years to complete, compared with an approximate wait time of 6 years in other jurisdictions.
CAISO has made several recent changes to make its queue more efficient, in compliance with FERC Order 2023. In 2024 FERC approved reforms including identifying zones that have available transmission to accommodate projects, spurring development, as well as zones that require developers to pay for upgrades. CAISO will consider projects for evaluation based on three criteria: project viability, system need, and commercial interest. The commercial interest category is meant to reflect utility procurement mandates in the state, including those for storage. Across various RTOs, the identification of “fast track” options to accelerate the processing of items in the queue could have substantive impacts on which generation gets built. For example, prioritizing capacity that can help meet clean energy goals could enable a different generation mix than prioritizing capacity that most effectively serves reliability needs.
Storage is also an excellent candidate for using surplus interconnection service (SIS). FERC Orders 860 and 2023 require RTOs and ISOs to facilitate projects that can take advantage of interconnection capacity that is not fully utilized. MISO updated its surplus interconnection service approach in 2021 to enhance its use, and SPP also offers an accelerated timeline for interconnection for projects looking to take advantage of existing interconnection rights. PJM is considered to be lagging in this space, with SIS being underused in the region. Clean energy advocates have expressed frustration with the lack of flexibility in the PJM SIS process, which often concludes that an SIS project would have a negative impact on the grid or other projects in the queue, without conducting studies that consider interconnection of customers’ plans for managing supply. Following the high capacity prices in 2024, PJM submitted several reforms to facilitate new supply coming online, including updates to the SIS process, to FERC. Those changes were approved by FERC in February 2025 and may help increase battery storage capacity in the region.
Compensation for Resource Adequacy: Regions also have different approaches for compensating storage resources for their contributions to resource adequacy. In regions with capacity markets (PJM, ISO-NE, and NYISO) and in regions with other methods for securing sufficient resources, energy suppliers are often “accredited” at some rate that adjusts their installed capacity to some amount that better reflects their contribution to resource adequacy. Accredited capacity of a resource is lower if it is less likely that the resource can offer supply when demand is high or supply is low. Each region has a different approach to accreditation, using different models, time frames for analysis, and underlying assumptions. Different regions also have different load profiles and resource mixes that can affect the marginal contribution of any given energy supplier to reliability. The result is that stand-alone storage faces different levels of capacity adjustments in different markets.
Table 2 shows different capacity adjustments for different durations of storage by ISO. Some of these are estimated figures or are still under development and review, but the table offers evidence that storage accreditation varies substantially across regions, in terms of both the types of storage eligible to supply capacity and the levels of accreditation. These accreditations are subject to change over time as renewable generation and energy storage capacity increase in the region.
Bidding Rules: Grid operators can also set rules that dictate how suppliers should operate in wholesale markets. For energy storage, which alternates between acting as demand and acting as supply, market participation is a bit more complex than for generators. Generally, storage owner/operators submit bid and offer spreads in the energy market, which establish the prices at which they would purchase power to charge and at which they would discharge and sell energy into the market. There is usually a gap between these two prices where battery operators would hold charge until higher prices come along and make it more profitable to sell. While traditional generators are thought to bid their marginal cost of generating energy in competitive markets, economists expect battery operators would set their selling price based on the opportunity cost of discharging. In other words, if a battery operator expects to be able to sell a MWh for $50 at 5 p.m., the operator may not be willing to sell it for $20 at 4:50 p.m., even if the marginal cost of charging that MWh is less than $20.
State of Charge Requirements: Most ISO markets explicitly model the state of charge of participating battery storage to ensure that battery charging and discharging schedules selected by the market software are feasible. This may include estimating typical charging and discharging behavior across different products, including ancillary services. Different strategies can be used to incorporate storage operational limits to market operations. These include allowing storage owners to make offers and bids that reflect storage owners’ own estimates of opportunity costs; allowing owners to self-schedule their discharging and charging, or to specify a target state of charge for a specified future time; and allowing system operators to “exceptionally dispatch” storage, overriding self-schedules or market schedules. Markets today allow storage operators to reflect energy constraints in their offers and bids but also may have minimum state of charge requirements to secure some operational certainty over energy availability from storage. State of charge requirements vary by market.
Access the report here
