FERC Order 2222 was issued in September 2020 with a clear objective: remove barriers to DER aggregator participation in wholesale electricity markets operated by Regional Transmission Organizations and Independent System Operators. The order required each RTO/ISO to revise its tariff to allow DER aggregations to participate in all capacity, energy, and ancillary service markets for which they are technically capable. It directed RTOs to eliminate minimum size thresholds that excluded small resources, to develop aggregation registration frameworks, and to establish coordination mechanisms between aggregators and distribution utilities.
The order set a compliance deadline of 270 days, with extensions possible. What followed was a multi-year process of compliance filings, comment rounds, FERC acceptances and rejections, and staggered implementation timelines that varied significantly across ISOs. Understanding where things actually stand, rather than where the order directed them to be, requires looking at each major RTO separately.
The Core Requirements of Order 2222
Before examining implementation status, it's worth being precise about what the order actually required, because confusion about this is common.
Order 2222 required RTOs/ISOs to: (1) allow DER aggregations to participate in all wholesale markets for which they are technically capable, regardless of location; (2) remove minimum size limitations that effectively excluded small DERs, with a default 100 kW aggregation minimum unless the RTO demonstrated good cause for a different threshold; (3) establish registration processes that allow aggregators to register their DER compositions with the ISO, including DER location, type, and capability; (4) develop coordination frameworks that specify how ISOs will interact with distribution utilities and state regulators regarding DER aggregations on distribution systems; and (5) set rules for how metering and telemetry will be handled for aggregated DERs that may not individually have the metering required for wholesale market participation.
The order explicitly did not pre-empt state utility commission authority over distribution systems, and it directed ISOs to develop coordination mechanisms that respect that authority. This created significant complexity because distribution utilities in different states have different regulatory requirements for DER interconnection and market participation notification.
Implementation Status by ISO
PJM filed its Order 2222 compliance tariff revisions and received FERC acceptance, launching its DER aggregation framework in 2022. PJM's implementation allows aggregations as small as 100 kW to participate as Demand Response resources and, with appropriate metering, in capacity and energy markets. The coordination process between PJM and distribution utilities requires aggregators to notify the relevant distribution company of DER registrations, with the distribution company having an opportunity to flag reliability concerns but not a general veto over market participation.
CAISO's compliance path was more extended, with multiple rounds of stakeholder engagement and tariff filing before reaching an accepted framework. CAISO implemented its Distributed Energy Resource Provider (DERP) model, which allows aggregations of DERs as small as 500 kW to participate in energy and ancillary service markets. The coordination mechanism with California's investor-owned utilities involves a distribution study process for aggregations that may affect distribution operations. In practice, the timeline for that coordination process has been a friction point for aggregators trying to register new portfolios.
NYISO's implementation reflects New York's Reforming the Energy Vision regulatory context, which created a more developed framework for DER market participation than most other states. NYISO allows DER aggregations in both the NYISO wholesale markets and through the Demand Response programs, with coordination with the state's distribution utilities through a data sharing agreement framework.
MISO and SPP have had more extended compliance timelines. MISO's DER aggregation framework received FERC acceptance, but the practical market pathways for DER aggregations within MISO's capacity markets involve interactions with state commissions and load-serving entities that add complexity not present in the order itself. SPP's implementation has been slower, reflecting the lower DER penetration in much of its territory and a more cautious stakeholder process.
ISO-NE has worked through compliance with particular attention to the coordination framework with New England distribution utilities. New England's distributed solar growth has been concentrated in Massachusetts, where utility coordination requirements are significant. ISO-NE's implementation includes specific telemetry and metering requirements for DER aggregations that participate in real-time energy markets.
What Has Not Changed
It's important to be direct about the gaps between Order 2222's intent and current operational reality.
In most ISOs, the practical market revenue available to DER aggregations is concentrated in demand response programs and capacity markets, not real-time energy dispatch. Energy market participation for DER aggregations requires near-real-time telemetry, sub-5-minute dispatch capability, and metering accuracy that most behind-the-meter DERs don't currently have without additional investment. The market architecture for DER energy dispatch is defined in the tariffs, but the operational infrastructure, both at the ISO and at the DER site, is not universally in place.
The coordination frameworks between ISOs and distribution utilities remain procedurally complex in most territories. An aggregator trying to register a portfolio that spans multiple distribution utility service territories faces separate notification and study processes in each territory, with different timelines and requirements. This procedural burden is manageable for large aggregators with dedicated regulatory staff, but it's a significant barrier for smaller operators building portfolios of 5 to 20 MW in a single ISO market.
We're not saying Order 2222 has failed to achieve its objectives. The regulatory foundation for DER market participation is now in place across all major US RTO/ISO markets. The remaining gaps are operational and procedural, not fundamental policy barriers. That's meaningful progress.
What Aggregators Should Be Preparing Now
For an operator building a DER portfolio with an eye toward wholesale market participation, the practical priorities are shaped by the current state of implementation.
Metering and telemetry upgrades are the most common bottleneck. Most behind-the-meter DER assets have adequate metering for utility billing and aggregator performance tracking, but not the ISO-grade metering required for real-time energy market participation. Understanding the metering requirements for the specific markets you want to participate in, before making portfolio acquisition decisions, avoids expensive retrofits after the fact.
Registration processes should be started well ahead of when you want to dispatch. In most ISOs, DER aggregation registration involves coordination with the distribution utility, a tariff filing with the ISO, and an enrollment process that can take 60 to 180 days from start to market participation. If you're planning to bid into the summer capacity market, starting registration in November is not sufficient lead time.
Dispatch capability at the asset level matters more than aggregation size for real-time market participation. An aggregation of 50 MW that can only respond to a dispatch signal within 30 minutes cannot participate in regulation or most ancillary service markets. Investing in dispatch automation infrastructure, the ability to issue a dispatch signal and receive confirmation of execution within seconds, is a prerequisite for the markets with the highest capacity revenue potential.
The Dispatch Intelligence Layer
What Order 2222 created is the market access framework. What it didn't create is the dispatch intelligence required to operate profitably within that framework. An aggregator with market access can still leave revenue on the table if their dispatch decisions are based on manual scheduling, static bid curves, or day-old forecast data.
The optimization problem for a DER aggregation participating in ISO wholesale markets involves: selecting which assets to bid into which markets for each operating day based on their state and capabilities, constructing bid curves that reflect the actual cost of dispatching each resource, managing across the simultaneous constraints of the ISO market requirements and the underlying distribution utility interconnection requirements, and responding to real-time market prices and dispatch instructions with sufficient speed to maintain market standing.
This is the technical layer that determines whether Order 2222's market access translates into actual revenue for DER operators. The regulatory pathway is open. The competitive advantage comes from executing on it with better forecast models, tighter dispatch automation, and smarter bid optimization than the rest of the market.