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№ 25 · appended

ISO New England opens its markets to distributed energy aggregations on 1 November 2026, six years after Order 2222

On 1 November 2026, 100 kW of somebody’s batteries stops being a utility programme and becomes a market participant with an asset identifier and a settlement account. That is the whole content of Order 2222. A utility programme is bilateral: the utility sets the price, the call window and the exit terms, and the customer’s only leverage is to leave. A market participant faces a price it did not set and can beat. Which of those a household battery is decides whether the edge has bargaining power or only a rebate. The second reason to care is the comparison. The same federal mandate, issued in September 2020, has produced a live market in New England roughly on the schedule ISO-NE filed in 2022, and a proposed February 2028 date at PJM, the largest RTO in the country. The variable being measured there is not the technology.

ISO New England opens its markets to distributed energy aggregations on 1 November 2026, roughly on the schedule it filed in 2022. The date is the least interesting part: what opens is a registration process, and the registration process is where the threshold actually sits.

ISO New England's rules implementing FERC Order No. 2222, the 2020 order requiring organised wholesale markets to admit aggregations of distributed energy resources, take effect in its energy and ancillary services markets on 1 November 2026. The participant readiness page ISO-NE maintains for the project, checked on 13 September 2026, sets the minimum size of an aggregation at 100 kW, records that the eMarket sandbox opened with the new day-ahead asset functionality on 30 July 2026, and puts asset registration in the fourth quarter of 2026, handled case by case through ISO Asset Registration. Roles in the production system are still marked as to be determined.

Seven participation models are on offer. SODERA is settlement-only, built from settlement-only generators and load assets. DRDERA mixes settlement-only generation with demand response resources and may include load. The rest are the modelled generator asset, the binary and continuous storage facility models, the existing demand response resource, and the alternative technology regulation resource, which has a floor of 0.1 MW. A single resource or aggregation of 5 MW or more sitting at one node cannot be buried inside a wide aggregation: ISO-NE requires it to participate standalone or through a geographically tighter one.

Where the date came from

The date is not new, and that is part of the point. ISO-NE proposed it in its Order 2222 compliance filing of 2 February 2022 in docket ER22-983, asking for 1 November 2026 for most of its tariff changes, with an earlier tranche effective 1 November 2022 covering the changes needed to let DER aggregations qualify for forward capacity auctions, beginning with the auction for the 2026-2027 capacity commitment period.

That earlier tranche matters, because it means the capacity market is not a second go-live still to come. Access to capacity revenue was legislated in the same 2022 filing. What remains is qualification, and qualification is not a formality. [UNVERIFIED: some secondary summaries place an ISO-NE capacity market date of 1 February 2027 tied to the 2028/29 commitment period. That pairing tracks PJM's proposed schedule, not ISO New England's, and no ISO-NE source consulted here states it. Treat any separate ISO-NE capacity go-live date as unconfirmed.]

The friction is in qualification, not in the go-live

As recently as 30 March 2026, ISO-NE and the NEPOOL Participants Committee were still filing tariff language on this. Their section 205 filing of that date, seeking an effective date of 29 May 2026, sets out how a distributed energy resource establishes the equivalent of Network Resource Capability and Capacity Network Resource Capability, the interconnection service levels that determine whether a resource can sell capacity at all.

The mechanics that filing describes are the real threshold. A distribution-connected, front-of-meter generator seeking capacity revenue must submit the same materials as a transmission-connected plant, be included in a Capacity Network Resource group study, and secure a Capacity Supply Obligation before it is allocated the capacity equivalent. Active demand capacity resources face an all-or-nothing deliverability analysis: either the resource can deliver into its load zone or it cannot. So a 100 kW aggregation clears the market's size test and then walks into a qualification process built for generating stations, with a group study, a queue and an auction result standing between it and a capacity payment.

Why it matters

Two things, and the first is the one worth holding onto. On 1 November 2026, 100 kW of somebody's batteries stops being a utility programme and becomes a market participant with an asset identifier and a settlement account. That distinction is the entire content of Order 2222. A utility demand-response programme is a bilateral arrangement in which the utility sets the price, the call window, the performance test and the exit terms, and the customer's only real option is to leave. A market participant faces a price it did not set, that it can be beaten by, and that it can also beat. Which of those a household battery is determines whether the edge has bargaining power or only a rebate cheque. Everything else about Order 2222 is plumbing for that one change.

The second thing is uncomfortable. Order No. 2222 was issued on 17 September 2020 and clarified on rehearing on 18 March 2021 and 17 June 2021. ISO New England is opening roughly on the schedule it filed in early 2022. PJM Interconnection, the largest RTO in the country, has proposed pushing its DER aggregation model to February 2028, which would put implementation about seven and a half years after the order issued. [UNVERIFIED: PJM's proposed February 2028 date is drawn from trade reporting on PJM's stakeholder materials and compliance filings, not read from the FERC docket.]

The reasons offered for that gap are partly about FERC itself, which took months and in one instance the better part of a year to rule on successive PJM compliance filings, and partly about PJM's stated need for roughly two years of runway after its final approval. Both are real. Neither is technical in the sense that matters here. The same federal mandate, applied to two neighbouring markets with comparable distribution technology, has produced a live market in New England and a moving deadline in the largest market in the country. When a rule opening markets to small resources takes six years in one region and possibly eight in another, the variable being measured is not the resources. It is the incumbent's appetite for the change, and the regulator's appetite for insisting.

It is also worth noting that ISO-NE's own path was not smooth. FERC accepted its compliance filing only in part and directed it to revise its metering and telemetry posture, having found that ISO-NE had not shown those requirements were not an undue barrier to individual resources joining an aggregation. [UNVERIFIED: this characterisation comes from contemporaneous trade reporting on the FERC order in ER22-983, not from the order text.] Metering requirements are where Order 2222 compliance keeps getting decided, in New England as in PJM.

What is still unknown

  • How many aggregations have registered, and for how many MW. Registration is only now opening.
  • Whether any independent third-party aggregator has qualified in New England, or whether participation in practice is utility-led.
  • How long the distribution utilities' DER eligibility reviews take, and what they ask for.
  • Whether ISO-NE has reaffirmed 1 November 2026 since its July 2026 readiness materials. No later confirmation was found.
  • The docket number and disposition of any 2026 ISO-NE filing that modifies the timeline.
  • Whether there is a distinct ISO-NE capacity market participation date beyond the 2022 tranche, and if so what it is.

Sources

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