Battery energy storage is one of the most talked-about tools in the clean energy transition, yet it remains one of the most frustratingly difficult to actually deploy at scale. Fear not, battery builders among us, a new resource is here to eliminate some of the friction.
The Center for Renewables Integration (CRI) and Pure Power Engineering have released a new white paper that cuts through the regulatory and operational complexity often associated with bringing projects online: Making Distributed Storage Work in Your State. Written by CRI co-founder Kerinia Cusick, DER interconnection expert and former DTECH Events speaker Mrinmayee Kale, and frequent Factor This power markets contributor Rao Konidena, the paper provides guidance for state utility commissions, legislators, energy offices, and consumer advocates.
The implementation challenge isn’t distributed storage technology, the authors argue, but rather the regulatory and operational framework that surrounds how we handle it.
Drawing on direct participation in state commission dockets and federal regulatory proceedings, the white paper’s authors identify four persistent challenges and the state-level solutions gaining traction. State commissions must resolve each to integrate third-party-owned battery energy storage systems (BESS) into distribution grids in a manner that benefits ratepayers. In a summary penned for Factor This, co-author Kerinia Cusick describes them as follows:
1. Distribution planning must include BESS as a peak reduction resource
Current EDC distribution planning processes largely ignore third-party BESS and assume the assets are not available to reduce peak, resulting in higher costs for ratepayers. Commissions need to ensure the EDCs have the assurances required to include BESS in their plans as peak reduction assets, which can include operating envelopes — predefined, seasonally variable charge/discharge windows, with associated nameplate capacity assumptions. Massachusetts and California have pioneered frameworks (Dispatch Limiting Schedules and Limited Generation Profiles, respectively).
2. Tariff structures must define both charging costs and compensation
Wholesale market access pathways for distribution-connected BESS are largely resolved under FERC Orders 841 and 2222, requiring a Wholesale Distribution Access Tariff (WDAT) from the EDC and a wholesale participation model from the ISO/RTO. Retail rates remain underdeveloped in most states. Commissions need to establish retail tariffs that reflect the value BESS provides, avoid double cost recovery of interconnection upgrades, and grandfather existing projects under the tariff in place at the time of interconnection. Connecticut’s probability-of-peak WDAT methodology and Rhode Island’s bi-directional retail rate proceeding are two examples.
3. BESS and load must not compete for the same substation capacity
EDC incentive structures and planning processes can create artificial conflicts between BESS and new load additions. Commissions should require BESS and large spot loads to be studied together and co-located where feasible. FERC’s emerging “bring your own capacity” framework — developed in the context of data center interconnection — offers a useful model to adapt at the state level.
4. Communication standards must be standardized, not utility-specific
Modern BESS inverters already comply with IEEE-1547 2018, IEEE-2030.5, and SunSpec CSIP — standards sufficient to meet EDC control, communication, and cybersecurity requirements. Commissions should mandate the adoption of these existing standards and prohibit EDCs from requiring bespoke SCADA solutions, which add cost for ratepayers and create barriers for developers operating across multiple utility territories.
To learn more, check out the full version of Making Distributed Storage Work in Your State.
