U.S. federal energy regulators are advancing market reforms that increasingly tie utility-scale battery storage revenues to verified grid performance-a shift with direct consequences for project finance, operations, and RTO tariff structures across major power markets.
The Federal Energy Regulatory Commission (FERC) has issued a series of orders and directives over the past year that collectively push grid-scale battery energy storage systems (BESS) toward performance-based compensation. Assets must now deliver the services for which they are paid or face financial penalties. The reforms span day-ahead capacity obligations, ancillary services, and the multi-service revenue stacking model that underpins most utility-scale storage business cases.
Background
FERC's engagement with storage market design dates to Order No. 841, issued in February 2018, which required RTOs and ISOs to establish participation models enabling storage to compete in capacity, energy, and ancillary service markets. The goal was to remove barriers created by market rules designed for conventional thermal generators-rules that did not reflect storage's unique ability to both consume and inject power. Order No. 2222, a subsequent sweeping directive, extended that framework to distributed energy resource (DER) aggregations, validating FERC's position that such resources should be able to capture their entire value stack.
Despite those foundations, enforcement gaps and market design inconsistencies allowed storage operators to optimize dispatch in ways that did not always align with grid needs. An analysis of bidding behavior in 2024 indicated that battery storage operators in CAISO may have been withholding offers in the day-ahead market to capitalize on price spikes in the real-time market, according to researchers at Resources for the Future. That behavior highlighted the tension between storage operators' economic incentives and the grid services regulators intend to procure.
Details
The most concrete recent action came in February 2025, when FERC approved a PJM Interconnection proposal to eliminate the categorical exemption that had previously allowed intermittent renewable and energy storage assets to avoid participation in PJM's capacity market. The ruling requires all existing solar, wind, and battery storage projects with Capacity Interconnection Rights to participate in PJM's Reliability Pricing Model beginning with the 2026/2027 Base Residual Auction. PJM argued, and FERC agreed, that the exemption enabled potential supply withholding that could inflate price signals and compromise reliability.
The decision introduces direct performance obligations for storage operators in PJM-the nation's largest grid-alongside existing non-performance charges. For capacity market improvements beginning with the 2026/2027 delivery year, PJM implemented FERC-approved measures to establish a uniform Non-Performance Charge rate and amended the PJM Tariff to make clear that being exempt from the must-offer requirement is not a defense against claims of market power.
At ISO New England, FERC in January 2024 approved the Day-Ahead Ancillary Services Initiative (DASI), which creates a market for 10- and 30-minute operating reserves procured jointly with the existing day-ahead energy market, targeting fast-ramping and fast-starting resources including energy storage. The DASI proposal took effect March 1, 2025, replacing non-market reserve procurement processes that ISO-NE and its participants said left resources underpaid and without financial incentives to perform in real time. ISO-NE estimated DASI would increase annual wholesale market costs by approximately $104.4 million, or 1.1%, based on 2019-2021 data.
At CAISO, regulators advanced a Storage Design and Modeling initiative that ran working group meetings through December 2025 to refine bid cost recovery and dispatch enhancement mechanisms for storage. Updated proposals were posted for stakeholder comment in early 2026. Revenue stacking complexity-balancing energy arbitrage, ancillary service commitments, and capacity obligations simultaneously-remains a core challenge for project developers operating across multiple RTOs.
Where a storage project stacks multiple revenue streams, dispatch optimization must balance competing obligations across energy arbitrage, ancillary services, and capacity commitments, and financing documents must define priority among those streams, allocate dispatch authority, and address the risk that regulatory changes to one market product may affect the economics of the others, according to legal analysis from Davis Graham. A BESS with a tolling agreement or capacity contract supporting 60 to 70 percent of projected revenue is a fundamentally different financing proposition from one relying primarily on energy arbitrage and ancillary services.
Outlook
FERC's regulatory agenda for storage is expected to intensify in 2026. FERC's evolving rules-covering market participation, co-location, and reliability-are reshaping opportunities for storage and inverter-based resources heading into 2026 and beyond, according to Morgan Lewis. PJM's regulation market is also undergoing a second phase of reforms planned for 2026, aimed at reducing over-procurement and better accommodating the growing share of storage and renewable resources in its fleet. Meanwhile, NERC reliability standards for inverter-based resources, including battery storage, are expected to be fully implemented by January 1, 2030. Developers and lenders that have not yet restructured financing models to account for performance obligations and non-performance penalty exposure face rising transactional risk as compliance deadlines approach across major RTOs.
