Storage Participation in Wholesale Markets

Regulatory developments include FERC’s orders on electric storage resources participating in the wholesale markets, qualifying facility eligibility, and reliability rules for inverter-based resources. 

FERC Orders

In February 2018, the Federal Energy Regulatory Commission (FERC) 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 is to remove barriers to electric storage resource participation in RTO/ISO markets.

Although 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 and can create barriers to entry for emerging technologies. The final rule aims to address those 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, and 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. Like 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 to accommodate the participation of DER aggregators under one or more participation models. The ISOs/RTOs will have broad discretion to craft those models, so long as they satisfy the criteria set forth in Order No. 2222.

These orders present 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 improves the market participation opportunities for those resources.

Moreover, the Commission believes the new reforms will 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 builds 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.

Emerging Regulatory Issues

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. That “must buy” obligation provides a major financial benefit to QFs, but has historically been a source of contention for utilities that are obligated to curtail or forgo other sources of energy in favor of the 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 recently 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 comprises 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 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, finding that FERC’s “send out” approach is a reasonable interpretation of the statute’s 80 MW requirement.

Barring any further legal challenge, the DC Circuit’s holding is beneficial for developers, particularly those seeking to add battery storage to existing renewable facilities, because it provides much-needed clarity on navigating PURPA’s size requirement. Developers can now design facilities with nameplate capacity in excess of the statutory limitation while still capturing the regulatory benefits of QF status, provided deliveries to the grid are inverter limited to 80 MW or less.

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 trio of orders in late 2022 focusing on increased 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.

FERC’s orders (1) directed NERC to develop a plan for formally registered IBRs for compliance purposes, (2) initiated a notice of proposed rulemaking directing NERC to develop new or modified reliability standards for IBRs; and (3) revised existing Reliability Standards to clarify the types of changes to an existing interconnected facility that must be evaluated through the interconnection process.

Storage as a Transmission Asset

Energy storage resources are undoubtedly versatile assets that can play a number of different roles on the grid, including to support transmission reliability. Energy storage resources that provide services like voltage support or absorption of excess power may be able to qualify as transmission assets, which, critically, allows for the system’s costs to be recovered through FERC-approved rates.

While FERC has long recognized that storage can qualify as a transmission asset, RTO/ISOs are increasingly incorporating changes to their tariffs and planning processes to allow for the consideration of electric storage resources as regulated transmission solutions.

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