Distributed energy resources (DERs) are spreading rapidly across the US grid. Managing this growing resource pool is one of the challenges facing utilities today.
FERC Order 2222 exists to help, but nearly six years after its introduction, implementation remains slow. This guide explains what it’s all about, and what utilities can do to move forward.
What is FERC Order 2222?
FERC Order 2222 mandates that DER aggregators of 100 kW or more are able to participate in wholesale electricity markets.
The Federal Energy Regulatory Commission (FERC) is the federal body responsible for regulating transmission and wholesale electricity markets in the US. It has jurisdiction over regional transmission operators (RTOs) and independent system operators (ISOs).
Under FERC Order 2222, individual asset owners such as a homeowner with solar panels or a business with a battery don’t participate in wholesale markets directly. Instead, they go through an aggregator, which pools multiple assets into a resource large enough to operate in those markets.
The order sets out how this participation should work, including rules around safety, compensation, and coordination between federal, state, and local levels.
The UK has already enacted something similar under code modification P415, which allows smaller-scale flexible resources to access the wholesale market and get paid for demand turn-down activity.
The US equivalent is larger in scope, but the underlying principle, i.e. giving distributed flexibility a route into markets, is the same.
What does FERC Order 2222 aim to achieve?
Wholesale and RTO markets were designed for traditional, large-scale generators (power plants, gas peakers, etc). They were not built with small, distributed resources in mind.
FERC Order 2222 addresses the mismatch. Its goals are to:
What are the timelines for the implementation of FERC 2222?
FERC initially issued Order no. 2222 in September 2020, with some updates since:
| Date | Milestone |
|---|---|
| 17 September 2020 | FERC issues Order No. 2222 (RM18-9-000) |
| 18 March 2021 | Order No. 2222-A which tightened DER aggregation eligibility and review rules |
| 17 June 2021 | Order No. 2222-B clarified interaction with demand response rules |
| 2022 onwards | RTOs/ISOs begin filing compliance plans with FERC |
Sources: FERC; National Law Review; MISO
Each RSO/ISO has implemented it to different timescales, with a breakdown of the expected finish date according to FERC below:
| Region | Expected to complete |
|---|---|
| CAISO | Complete (November 2024) |
| NYISO | End of 2026 |
| ISO-NE | November 2026 |
| PJM | February 2028 (proposed) |
| MISO | June 2029 |
| SPP | Q2 2030 (proposed) |
Source: FERC
Why has implementation been slow?
Three factors in particular explain why this has taken longer than anticipated.
1. Regulatory and stakeholder process drag
Each RTO and ISO has had to file its own compliance plan and then iterate on it through a stakeholder process involving utilities, states, aggregators, and consumer advocates.
These processes address reliability concerns, resolve jurisdictional tensions between FERC and state commissions, and negotiate cost recovery and risk allocation – but the whole process can take time.
2. The review and coordination burden
The order gives utilities the right to review DER aggregations for reliability before they can participate in wholesale markets. In principle this is a sensible safeguard but most utilities don’t yet have the systems to do it efficiently.
Without a clear map of where DERs are located and what they are already committed to, the review process can become a bottleneck that compounds the stakeholder and ecosystem delays.
3. The DER ecosystem is still maturing
In many regions, the underlying DER base and the utility processes needed to support them are still developing.
Even where rules exist on paper, actual market participation lags because business models are still being proven, and utilities and aggregators are still piloting and learning how to operate under the new framework.
What are the main barriers to DER participation?
For utility operators working to implement FERC Order 2222, there are barriers to navigate:
How can the right technology help?
Two types of tool can help support this mandate: one for market coordination, one for grid visibility.
Lowering barriers to entry
Some flexibility market platforms can run multiple market types at once, tailored to different use cases. This gives aggregators more routes to participate, and utilities more tools to procure the flexibility they need.
Gaining visibility over DER capacity
Before any market coordination can happen, utilities need to know where their DERs are and what they are already committed to. Visibility tools can fill in that blind spot, making approval processes faster and giving utility planners the confidence to act.
Managing multi-market conflicts
The challenge then becomes what happens when the same asset wants to serve multiple markets at once. A battery bidding into an ISO wholesale market under FERC Order 2222 might also be needed by the local utility to manage a peak constraint.
A market platform can help ensure that a bid into a wholesale market doesn’t compromise local grid stability, and can automate the “double-counting” checks that currently keep regulatory lawyers up at night.
Generating insights
Participation data helps offer up some actionable intelligence: how much flexibility is being delivered, what it costs, what its grid impact is. These insights allow operators to refine market design over time and build the evidence base that supports wider adoption.
Electron’s approach
FERC 2222 is a mandate, but Electron makes it manageable. Implementing it requires solving two distinct problems, and Electron has built tools for both.
Detecting DERs.
Utilities can’t approve the FERC 2222 aggregations for reliability if they don’t know where the assets are or what they are already committed to. ElectronCompass addresses this, giving utility planners way to detect hidden DER capacity and turn a manual review process into something that can scale.
Coordinating and activating DERs, at scale.
ElectronConnect then can act as the bridge between the RTO’s wholesale market needs and the utility’s local grid constraints. It’s the flexibility market software that supports utilities and grid operators to design, run, and manage flexibility markets at scale, and handles the technical complexity of publishing requirements, collecting bids, dispatch, and settlement.
That coordination layer is what makes FERC Order 2222 participation more practically workable.
FAQs
DER aggregators must reach at least 100 kW to participate in wholesale markets under the order. Individual market rules within specific RTOs may set higher thresholds.
No. Individual asset owners such as homeowners with solar panels participate through an aggregator, who pools multiple assets to meet market thresholds.
Simultaneous participation is possible but governed by strict rules designed to prevent the same flexibility being compensated twice. Coordination between the utility program and the wholesale market aggregator is required.
Code modification P415 in the UK allows smaller-scale flexible resources to access the wholesale market and receive payment for demand turn-down activity. It provides a useful reference point for how distributed flexibility can be integrated into wholesale markets in practice.
