Federal Regulatory Outlook for Electric Storage, QFs, and Inverter-Based Resources

FERC ORDERS

In February 2018, the Federal Energy Regulatory Commission issued Order No. 841, a landmark final rule amending FERC’s regulations to facilitate the participation of electric storage resources in the capacity, energy, and ancillary service markets operated by regional transmission organizations/independent system operators (RTOs/ISOs) (excluding ERCOT). [1] The goal of Order No. 841 was to remove barriers to electric storage resource participation in RTO/ISO markets.

While certain storage resources, such as pumped hydro resources, have been participating in RTO/ISO markets for years, the Commission observed that existing market rules designed for traditional resources do not recognize electric storage resources’ unique physical and operational characteristics, creating barriers to entry for emerging technologies. The final rule aimed to address such barriers by establishing the minimum requirements by which RTOs and ISOs will facilitate electric storage resource participation in wholesale markets.

The final rule applies to electric storage resources, which the Commission defined as any “resource capable of receiving electric energy from the grid and storing it for later injection of electric energy back to the grid.” This definition applies to all storage resources, irrespective of their storage medium (e.g., batteries, flywheels, compressed air, pumped hydro) and location on the grid (i.e., the definition applies to resources on the interstate transmission system, on a distribution system, or behind the meter). This expansive resource-neutral definition underscores the Commission’s view that market rules should not be designed for any particular electric storage technology.

The final rule imposes a 100 kilowatt (kW) minimum size requirement that is intended to balance the benefits of increased competition in RTO/ISO markets with the potential burden required to update RTO/ISO market clearing software to effectively model and dispatch smaller resources. RTOs/ISOs were required to develop their own models to facilitate the participation of electric storage resources to comply with Order No. 841, including qualification criteria and bidding parameters that reflect the physical and operational characteristics of the resource.

Informed by its experience administering Order No. 841, FERC issued Order No. 2222, a sweeping order that mandates reforms intended to facilitate the participation of distributed energy resource (DER) aggregations, which can include various storage resources, in the wholesale market.

As in Order No. 841, FERC mandated that ISOs/RTOs create or modify their wholesale market participation models to establish DER aggregators as a discrete market participant category and accommodate the participation of DER aggregators under one or more participation models. ISOs/RTOs have broad discretion to craft the models so long as they satisfy the criteria set forth in Order No. 2222.

These orders presented a major change in the administration of wholesale markets. The Commission found in Order No. 841 that requiring RTO/ISO markets to value electric storage resources as both supply and demand improved the market participation opportunities for those resources.

Moreover, the Commission felt the new reforms would improve market efficiency by enabling RTOs/ISOs to dispatch electric storage resources in accordance with the highest-value service they are capable of providing at that time, thereby better reflecting the value of storage as a marginal resource.

Order No. 2222 built on those reforms by validating FERC’s view that DERs can and should be able to realize their full value and in turn capture their entire value stack.

EVOLVING REGULATORY ISSUES

Generator Co-Location

Domestic electricity demand continues to surge, driven in part by large electricity customers such as data centers. These large customers often require vast amounts of energy to power advanced computing needs for cloud services, artificial intelligence applications, and data storage and are increasingly looking toward co-locating their facilities “behind the meter” alongside generators. Co-located configurations for large commercial or industrial electric power users are not uncommon, but the growth trend for data centers has placed a new spotlight on the grid and supply issues related to generator co-location and prompted federal regulators to take action.

In a rare move, in October 2025 the US Department of Energy exercised seldom-used authority to issue an advance notice of proposed rulemaking (ANOPR). The ANOPR instructed FERC to launch a rulemaking focused on the timely and orderly interconnection of large loads and co-located arrangements, including AI data centers. The ANOPR outlined a series of 14 principles that the DOE believes should guide FERC’s rulemaking efforts, including standardization to reliability and operations. As of this writing, FERC is continuing to review public input in response to the ANOPR’s proposals, but has been directed to act by April 2026.

In late 2025, FERC also directed PJM Interconnection, LLC, the nation’s largest grid operator, to reform its rules governing generation interconnection and transmission service for generators co-located with load. FERC found that PJM’s Open Access Transmission Tariff lacked sufficient rates, terms, and conditions of service that apply to such co-located arrangements.

The FERC Order directs significant changes to generation interconnection procedures and transmission services, including the creation of new alternatives to existing transmission services. Those alternatives would not require co-located load to become network load, thereby allowing the co-located load to withdraw electricity from the PJM transmission system earlier than may be otherwise achievable. While FERC’s directive is tailored to the rules and requirements within the PJM region, the Order is expected to more broadly provide a framework for addressing some of the core issues related to co-location and other large-load interconnection issues as similar configurations proliferate across the country.

These regulatory reforms, which offer flexibility to customers with co-located load, present an opportunity for energy storage resources. For example, energy storage can alleviate some of the immense back-up power needs for behind-the-meter data center configurations, thereby limiting the need for a data center operator to rely on the grid and increasing the operator’s ability to be a “flexible” load.

This flexibility could allow co-located load to take advantage of more adaptable transmission service options, such as the alternatives FERC directed PJM to implement that will facilitate quicker access to grid power. Data centers may also consider developing microgrid campuses that combine intermittent low- or zero-carbon clean energy with battery storage to be self-sufficient in lieu of paying for the costly and time-consuming transmission upgrades needed to power their facilities.

QF Status

Developers should be mindful of how they intend to observe size caps for federal regulatory status under the Public Utility Regulatory Policies Act of 1978 (PURPA), whether the project is a standalone energy storage resource or a conventional renewable energy facility paired with an energy storage resource. PURPA entitles qualifying facilities (QFs) to relief from certain regulatory burdens and requires incumbent utilities to purchase power from QFs directly or indirectly interconnected to their system. While the “must buy” obligation provides a major financial benefit to QFs, it has historically been a source of contention for utilities that are obligated to curtail or forgo other sources of energy in favor of QFs.

Not just any renewable facility can qualify as a QF: among other requirements, a qualifying small power production (i.e., renewable) facility may not exceed 80 MW (measured as net alternating current (AC)). FERC and the US Court of Appeals for the DC Circuit addressed this limitation in the Broadview proceeding, concluding that a hybrid solar-plus-storage facility with a nameplate capacity above the 80 MW limit can nevertheless qualify as a QF if its output to the grid does not exceed that cap. [2] The facility at issue in Broadview comprised a solar array that can produce 160 MW and a battery that can store 50 MW, paired with a bank of AC inverters limiting the output of the facility delivered to the grid to 80 MW.

Under FERC’s preexisting “send out” policy, first articulated in Occidental Geothermal, Inc., [3] FERC considers a facility’s “power production capacity” to be its total output instead of the nameplate capacity of its individual subcomponents. This would mean the hybrid facility could qualify as a QF because its total output was limited by design to be no more than 80 MW.

FERC initially declined to extend that policy to the hybrid facility, but then reversed on rehearing and found that the facility was a QF after all. The DC Circuit affirmed FERC’s position, applying the Chevron doctrine to defer to FERC’s reasonable interpretation of its statutory authority [4] and holding that FERC’s “send out” approach is a reasonable interpretation of the statute’s 80 MW requirement.

The US Supreme Court subsequently vacated the DC Circuit holding as part of a spate of orders directing lower courts to reconsider their holdings following the Court’s Loper Bright and Relentless decisions, which overruled Chevron. However, on remand, the DC Circuit again sided with FERC in late 2025, exercising its own independent judgment to find that a small power production facility’s power production capacity refers to its maximum net output of AC power to the electrical grid at any given point in time.

RELIABILITY RULES FOR INVERTER-BASED RESOURCES

Following a series of grid reliability events involving nonsynchronous generators observed by the North American Electric Reliability Corporation (NERC), FERC issued a series of orders targeting reliability-related requirements for inverter-based resources (IBRs). FERC considers IBRs to include all generation resources that connect to the electric power system using power electronic devices that change direct current (DC) power produced by a resource to AC power, including battery storage resources.

FERC’s orders are intended to ensure that IBRs are configured and operated in a manner that enhances grid reliability in accordance with NERC Reliability Standards. While some IBRs meet the appropriate size thresholds and are already subject to the Reliability Standards, the revisions will likely expand that scope to cover more IBRs.

In late 2023, FERC issued Order No. 901 directing NERC to develop or modify reliability standards specifically to address reliability concerns attributable to IBRs in four areas:

• Data Sharing
• Model Validation
• Planning and Operational Studies
• Performance Requirements [5]

As required by Order No. 901, NERC developed the first two of the expected suite of IBR-related reliability standards, which FERC proposed to adopt through the issuance of a notice of proposed rulemaking (NOPR) in December 2024. The NOPR proposes to approve rules covering the ability of IBRs to “ride through” frequency and voltage excursions such as faults on the transmission system.

NERC will continue to file the remaining reliability standards directed by Order No. 901 through late 2026, with full implementation of the standards by January 1, 2030.