The integration of battery energy storage systems (BESS) into power grids has been accelerated by regulatory frameworks designed to accommodate their unique capabilities. These regulations address technical, economic, and operational challenges while ensuring grid reliability and fair market participation. Key policies such as FERC Order 841, capacity market rules, and grid code compliance have laid the foundation for battery storage to participate in wholesale electricity markets and provide critical grid services. Interconnection standards and revenue mechanisms further enable batteries to contribute to grid stability and efficiency.

FERC Order 841, issued in 2018 by the Federal Energy Regulatory Commission, is a landmark regulation that removes barriers to energy storage participation in wholesale markets. The order mandates regional transmission organizations (RTOs) and independent system operators (ISOs) to establish market rules that recognize the physical and operational characteristics of storage. This includes allowing storage resources to provide capacity, energy, and ancillary services, regardless of their charging source. Order 841 also requires that storage be compensated for the full range of services it can provide, ensuring economic viability. Compliance filings from RTOs and ISOs have led to tailored rules for storage, such as minimum size requirements, duration thresholds, and bidding parameters.

Capacity market rules have also evolved to accommodate battery storage. Traditionally, capacity markets compensate resources for their ability to deliver energy during peak demand periods. Batteries, however, have limited energy duration compared to conventional generators. To address this, some markets have introduced modified rules, such as PJM’s capacity performance construct, which requires resources to sustain output for longer durations. Batteries can participate by pairing with other resources or by meeting stricter performance standards. ERCOT, in contrast, does not have a formal capacity market but allows storage to participate in the energy and ancillary services markets, where fast response times are highly valued.

Grid code compliance ensures that battery systems meet technical requirements for safe and reliable grid operation. These codes cover voltage and frequency regulation, ramp rates, and fault ride-through capabilities. For example, the North American Electric Reliability Corporation (NERC) sets standards for inverter-based resources, including batteries, to maintain grid stability during disturbances. European grid codes, such as those under ENTSO-E, require storage systems to provide synthetic inertia and fast frequency response, mimicking traditional synchronous generators. Compliance with these codes often necessitates advanced power electronics and control systems, increasing the cost but also the value proposition of battery storage.

Interconnection standards are critical for integrating batteries into the grid without causing disruptions. The IEEE 1547-2018 standard outlines technical requirements for distributed energy resources, including storage, to ensure seamless interconnection with distribution systems. Key provisions include voltage regulation, anti-islanding protection, and dynamic reactive power support. Utilities often require additional studies, such as short-circuit analyses and transient stability assessments, to evaluate the impact of battery installations. Streamlined interconnection processes, like those developed by California’s Rule 21, reduce delays and costs for storage projects.

Revenue mechanisms for battery storage are diverse, reflecting the multiple services they can provide. Ancillary services, such as frequency regulation and voltage support, are among the most lucrative. Batteries excel in fast-frequency response markets due to their millisecond-scale response times. In PJM, storage resources earn revenue through RegD and RegA signals, while Australia’s National Electricity Market (NEM) offers frequency control ancillary services (FCAS) payments. Energy arbitrage, where batteries charge during low-price periods and discharge during high-price periods, is another revenue stream, though its profitability depends on price volatility and battery efficiency.

Capacity payments, though less common for standalone storage, are becoming more accessible. The UK’s Capacity Market now allows batteries to secure contracts, provided they meet minimum duration requirements. Similarly, New York’s Value of Distributed Energy Resources (VDER) program compensates storage for its locational and environmental benefits. Emerging mechanisms, such as resource adequacy agreements in California, guarantee fixed payments for storage capacity, reducing revenue uncertainty.

Despite these advancements, challenges remain. Duration limitations restrict batteries from replacing conventional peakers in some markets. Regulatory uncertainty in regions without clear storage policies discourages investment. Additionally, dual-use applications, such as electric vehicle batteries providing grid services, face regulatory hurdles.

Future regulatory developments may focus on hybrid resource participation, where storage is paired with renewables or thermal plants. FERC Order 2222, for instance, enables distributed energy aggregations to compete in wholesale markets, opening new opportunities for batteries. Standardization of grid codes and interconnection processes across regions could further reduce barriers.

In summary, regulations like FERC Order 841, adapted capacity market rules, and stringent grid codes have enabled batteries to become a cornerstone of modern power grids. Interconnection standards ensure technical compatibility, while diversified revenue mechanisms enhance economic feasibility. Continued regulatory evolution will be essential to fully unlock the potential of battery storage in grid applications.