The framework that governs how DERs participate in wholesale electricity markets was designed after FERC Order 2222 (2020) and subsequent ISO rule changes. On paper, the path exists: an aggregator or utility-managed VPP can register a DER aggregation as a market resource, participate in capacity markets, and dispatch in response to ISO signals. In practice, operations teams working at the intersection of ISO market participation and distribution DER management face gaps that regulatory frameworks acknowledge but haven't fully closed.
This piece is not a policy argument; it is a description of the operational friction points that arise from the current state of ISO-to-utility coordination, and what that means for teams trying to build functional DER programs today.
The two-authority problem
Distributed energy resources physically connected to distribution circuits operate under dual authority: the distribution utility controls the interconnection and has reliability obligations for feeder operations; the ISO controls the wholesale market and can issue dispatch signals that affect the same assets. When both authorities are present and their signals don't coordinate, operations teams are caught in the middle.
A concrete example: a DER aggregation enrolled as an ISO demand response resource receives a real-time dispatch signal from the ISO to reduce load by 3 MW within 10 minutes. The aggregator (or utility operating the VPP) dispatches enrolled batteries on multiple distribution feeders to begin discharging. One of those feeders, feeder F-17, is currently operating under a SCADA constraint because a switching operation is in progress following a fault upstream. Discharging batteries on F-17 while the switching operation is active creates a voltage stability risk that the distribution utility's control room is managing in real-time and that the ISO dispatch system has no visibility into.
The gap between ISO dispatch timing (real-time market dispatch, 5-minute intervals) and distribution constraint awareness (SCADA feeder state, updated continuously but not shared with the ISO in real-time) is structural. FERC Order 2222 doesn't resolve this gap; it creates the market pathway while leaving the real-time coordination mechanism to bilateral agreements and operational procedures that each ISO and its member utilities have to work out separately.
Settlement interval mismatches
ISO energy market settlement happens in 5-minute intervals in most organized markets. Demand response capacity performance settlement typically occurs over longer windows: hourly or 30-minute performance intervals, depending on the market. Utility-side AMI metering that captures the load reduction delivered by enrolled customers operates on 15-minute intervals for most deployed AMI systems, with some advanced AMI installations supporting 5-minute intervals.
The settlement process requires mapping DER-delivered performance (what actually happened at the asset level) to the ISO settlement interval structure (what the ISO is measuring and settling against). If the utility's AMI provides 15-minute interval data and the ISO settlement requires 5-minute data, the mapping requires interpolation or estimation. If a battery asset's SoC data arrives with a 3-minute lag from the vendor API, the timestamped dispatch event record may not align cleanly with the ISO settlement interval that the dispatch was supposed to serve.
For small discrepancies, these mismatches create reconciliation work at settlement time. For larger discrepancies during high-value events (scarcity pricing, emergency capacity calls), they can create material settlement disputes. The resolution path involves manual review of telemetry records from the DER management platform, SCADA feeder data, and AMI interval reads, mapped against ISO settlement data, reconciled by someone who understands all three data systems. This process exists at most DER aggregators; it is labor-intensive and error-prone.
The registration gap for small DER aggregations
FERC Order 2222 created the regulatory pathway for DER aggregations to participate in ISO markets, but each ISO's implementation of the rule sets its own minimum size thresholds, registration requirements, and aggregation geographic constraints. For municipal utilities and cooperatives evaluating whether to register their DER program as an ISO market resource, the registration overhead is a significant hurdle.
A cooperative managing 500 enrolled battery customers with 3 MW of aggregate enrolled capacity needs to: create a market resource registration for the aggregation, establish a meter aggregation plan that maps enrolled meter points to the ISO resource ID, implement the ISO's telemetry submission requirements (some ISOs require direct meter data submission to the ISO rather than aggregated submission through the utility), and navigate the ISO's testing and qualification process for a new market participant type.
The registration overhead is calibrated for larger resources. A 100 MW gas peaker navigating ISO registration has a dedicated regulatory and market operations team. A 3 MW cooperative DER program has one or two staff who also handle every other aspect of the cooperative's operations. The registration cost-benefit calculation for small DER programs often doesn't favor ISO market participation at current market prices and registration overhead levels.
This is not a criticism of the ISOs; it reflects that the registration framework was designed for traditional resource types at traditional scales, and adaptation takes time. It does mean that the bulk of DER program value for municipal utilities and cooperatives currently comes from distribution-level demand management programs rather than wholesale market participation, and that is where the operational tools need to perform well today.
Where real-time coordination is emerging
Some ISOs are developing distribution-level coordination frameworks that create formal channels for utilities to communicate distribution constraints to the ISO in real-time. The concept, sometimes called Distribution System Operator (DSO) coordination or distribution-to-transmission coordination, creates a protocol by which the distribution utility can signal the ISO when a distribution constraint limits DER dispatch on specific feeders, and the ISO can factor that constraint into its dispatch decisions.
These frameworks are in pilot stages in a few ISO territories as of late 2025. They represent the right architectural direction: instead of having operations teams manually manage the gap between ISO dispatch signals and distribution constraints, create a machine-readable protocol that lets both systems communicate the constraint in real-time. The operational burden of running dual-authority coordination manually is not sustainable as DER penetration increases and ISO DER dispatch becomes more frequent.
What operations teams need to do in the interim
Until real-time ISO-to-distribution coordination frameworks are widely deployed, operations teams running DER programs with ISO market exposure need to build their own coordination procedures.
The most important piece is a distribution constraint layer in the DER dispatch system: before issuing a dispatch signal in response to an ISO dispatch notification, the system should check whether any feeder serving enrolled assets has an active constraint that limits dispatch on that feeder. This check requires access to current SCADA feeder state, which means the DER management platform needs a data link to SCADA, not just to the battery vendor APIs and DERMS enrollment system.
The second piece is documentation: an operations procedure that defines what happens when the ISO dispatches the DER resource but distribution constraints prevent full delivery. The ISO market requires a response; the distribution utility has a feeder reliability obligation. The procedure for flagging a partial delivery event, notifying the ISO of a force majeure or distribution constraint exception, and documenting the constraint for settlement purposes needs to exist in writing and be known to the operations team before the first conflict occurs, not improvised in the middle of a peak event.
The gap we are describing is real and not attributable to failures by any party; it is an emergent consequence of distributed energy resources existing at a scale that the original architecture of both distribution utility operations and wholesale power markets wasn't designed to accommodate simultaneously. The solutions require coordination across regulatory jurisdictions and technical standards bodies that takes time. In the interim, the operations teams running these programs need clear procedures for navigating the gaps that exist today.