On September 17, 2020, FERC issued Order 2222 — formally titled Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators. The order required all RTO/ISO operators to revise their tariffs to allow aggregations of distributed energy resources to participate directly in wholesale energy, capacity, and ancillary services markets. For community solar operators sitting on portfolios of behind-the-meter solar, storage, and flexible load, the implications were significant — though most of those operators didn't feel the effects until the ISO compliance tariff filings started landing years later.
This post is not a legal analysis of the order. It's a practical briefing for program operators who want to understand what FERC 2222 means for their capacity market options and what the ISO-specific compliance tariffs require before a DER aggregation can show up in an auction.
What the Order Actually Changed
Prior to Order 2222, the rules governing wholesale market participation were written around large, utility-scale resources — generators, transmission-connected demand response providers, and large commercial loads with existing billing relationships with utilities. Behind-the-meter solar spread across thousands of subscriber accounts had no pathway into these markets. The metering, telemetry, and dispatch capability requirements presumed single-site resources with dedicated interconnection agreements, not aggregations of 500 rooftop installations with varying inverter brands and AMI meter read intervals.
Order 2222 broke that presumption. It required each ISO/RTO to create a participation model for DER aggregations — a defined market registration type that acknowledges the disaggregated, heterogeneous nature of behind-the-meter assets. Critically, it directed ISOs to revise their metering and telemetry requirements to accommodate aggregated DER rather than requiring each asset to meet the same standards as a transmission-connected generator.
The order also required ISOs to address the "distribution-wholesale interface" — the question of how DER dispatch instructions issued by ISO market operations coordinate with distribution utility operations and interconnection rules. This remains the most technically complex provision, and the one where ISOs have taken the widest variety of approaches in their compliance filings.
ISO Compliance Tariff Filings: Where Things Stand
FERC didn't set a single compliance deadline — it gave ISOs a filing window and the compliance tariffs have arrived at different points. PJM, ISO-NE, NYISO, MISO, SPP, and CAISO have all filed compliance tariffs, though each looks materially different from the others. FERC has accepted most with modifications, and the case law on what "compliance" actually means for each provision continues to accumulate.
For community solar operators, the three most relevant ISOs are PJM (covering the mid-Atlantic and Midwest), ISO-NE (New England), and NYISO (New York). All three have filed and received FERC acceptance of their Order 2222 compliance tariffs, though with different structures for minimum aggregation size, telemetry requirements, and capacity qualification timelines. A subsequent post covers the ISO-NE vs. NYISO comparison in detail; this one focuses on the broader Order 2222 framework.
What "DER Aggregation Participation Model" Means in Practice
When an ISO establishes a DER aggregation participation model, it creates a registration pathway for an aggregator to enroll a portfolio of distributed assets as a single market participant. The aggregator doesn't register each solar installation separately — it registers the aggregate, subject to minimum size thresholds and documentation requirements about the constituent assets.
For capacity markets specifically, a DER aggregation enrolled under an Order 2222-compliant tariff is treated as a capacity resource for purposes of auction participation. The aggregator submits a capacity offer, receives a capacity obligation if cleared, and is responsible for delivering — or allowing dispatch of — the committed capacity when called. The aggregator bears the shortfall risk if the portfolio can't perform.
We're not saying that Order 2222 makes capacity market entry simple for community solar programs. The compliance tariff requirements — particularly around telemetry infrastructure, dispatch testing, and metering data quality — represent real technical barriers. What the order did was eliminate the regulatory barrier that had prevented DER aggregations from even seeking enrollment. The technical work is real; it's just no longer forbidden.
A Concrete Scenario: A Mid-Atlantic Community Solar Portfolio
Consider a community solar operator managing a 22 MW portfolio across five projects in Maryland and Virginia — all within PJM territory. Each project has a mix of subscriber-owned rooftop solar and a shared storage asset. The operator has been collecting interval meter data through a third-party AMI provider and has basic inverter monitoring through a DERMS platform.
Before Order 2222, this operator's path to ISO capacity markets would have required each project to qualify independently as a capacity resource — an impractical proposition for small BTM assets. After the PJM compliance tariff filing, the operator can pursue DER aggregation registration for the entire 22 MW portfolio as a single capacity resource, subject to meeting PJM's telemetry accuracy requirements, completing a dispatch test event, and filing the asset inventory documentation PJM's tariff requires.
The telemetry piece is where most operators get stuck. PJM requires aggregated DER telemetry to be reported at a resolution and accuracy that many AMI meter data feeds don't meet out of the box, particularly for aggregations where some assets are behind residential meters with 15-minute read intervals rather than submetered at higher resolution. Normalizing that data for ISO compliance purposes requires aggregation infrastructure that most community solar program operators don't have internally.
The Distribution Utility Coordination Requirement
Order 2222 included a provision requiring ISOs to establish a coordination mechanism with distribution utilities to ensure DER dispatch doesn't create safety or operational issues at the distribution level. Each ISO has implemented this differently, and the specifics matter for community solar operators whose assets are interconnected with a distribution utility rather than directly with the transmission system.
In PJM territory, the distribution utility coordination requirement means the aggregator needs to notify the relevant electric distribution company (EDC) when enrolling DER assets and must follow any local distribution constraints when dispatching. In practice, this creates a notification and coordination step that adds time to the enrollment process — and potentially creates local operating agreement requirements with the EDC that vary across PJM's 13-state footprint.
Community solar operators should plan for this coordination requirement. It's not a veto — the EDC doesn't have to approve every dispatch event — but the enrollment process requires establishing the communication channel, and some EDCs have been slower than others to set up the processes Order 2222 anticipated.
Capacity Market vs. Energy and Ancillary Services Markets
Order 2222 applies to energy, capacity, and ancillary services markets. Community solar operators who are new to wholesale markets often ask which market to enter first. Capacity markets are generally the most accessible starting point for programs with BTM solar and storage because:
- Capacity obligations are forward-looking — you're committing to be available to dispatch, not dispatching continuously in real time. This is more compatible with the operational model of a community solar program.
- Dispatch events in capacity markets are less frequent than real-time energy market participation, reducing the operational complexity of the first market participation experience.
- Capacity market revenue is relatively predictable once a clearing price is set in the auction, making it easier to budget and model program economics.
Energy market participation — bidding BTM generation directly into the day-ahead or real-time energy markets — requires much faster telemetry, near-real-time dispatch response, and more sophisticated co-optimization with subscriber self-consumption. That's a second-order consideration for most programs. Start with capacity.
What This Means Before You Start the Enrollment Process
The most common mistake community solar operators make when they start thinking about ISO capacity markets post-2222 is treating the FERC order as the finish line rather than the starting pistol. The order created the legal right; the technical work to exercise that right is what the ISO compliance tariffs define.
Before initiating ISO enrollment, operators should assess: whether their current metering infrastructure can generate ISO-compliant telemetry at the required resolution, whether their portfolio has sufficient size to meet the ISO's minimum aggregation threshold, and whether the distribution utility coordination process has been mapped out for each project's service territory.
None of these are dealbreakers — they're inputs to an enrollment timeline. A program that's 6 months from having the right telemetry infrastructure in place can plan accordingly. The operators who stall are the ones who discover the telemetry gap after they've started the ISO enrollment process rather than before.
Order 2222 is now several years old. The compliance tariffs are largely in place. The early-mover window for getting ahead of this capacity market opportunity is still open — but the programs that start the technical groundwork now are the ones who will clear capacity auctions in the near-term planning horizon.