FERC Order 2222, issued in September 2020, directed all ISOs and RTOs to develop tariff rules allowing DER aggregators to participate in wholesale electricity markets. The rulemaking was significant because it established a federal policy that distributed assets, including behind-the-meter batteries, residential smart thermostats, and commercial flexible loads, have a right to access the same markets that large power plants have participated in for decades.
But Order 2222 compliance has unfolded unevenly across the country. Some ISOs moved quickly to implement aggregation tariffs. Others have faced delays from state commission interactions, technical challenges in telemetry and metering requirements, or opposition from utilities concerned about double-counting of distribution-level resources. As of early 2026, the operational picture looks very different depending on which ISO your assets are located in.
This post focuses on the operational side: what it actually takes for a DER aggregator to participate in ISO wholesale markets, and where dispatch optimization fits into the process.
The Registration and Telemetry Foundation
Before a DER aggregation can submit bids into an ISO market, it has to meet the ISO's registration and telemetry requirements. These requirements exist because the ISO needs to be able to verify that the aggregation can perform as bid and that it is actually operating as instructed during dispatch intervals.
Registration typically requires a minimum aggregate capacity, often in the range of 100 kW to 1 MW depending on the ISO and the market product. Individual assets below that threshold can contribute to the aggregate, but the aggregation as a whole must meet the minimum. This is a meaningful barrier for operators working with small distributed assets. A residential virtual power plant with 500 homes each having 10 kW of flexible load capacity has 5 MW aggregate, but the individual assets are tiny and the metering infrastructure to document each one is costly.
Telemetry requirements specify how real-time operating data from the aggregate must be delivered to the ISO. CAISO, for example, requires registered DER aggregations to provide 10-second telemetry on actual production and consumption to the ISO's SCADA system via secure communication links. Operators who are accustomed to hourly or 15-minute interval metering for settlement purposes need to invest in near-real-time telemetry infrastructure to meet this requirement. This is not an optional enhancement for wholesale market participation: without it, you cannot pass the ISO's capability testing for market registration.
How Bids Are Structured
A DER aggregation participating in an ISO energy market submits bids that specify the aggregate's capability to produce or consume energy during each scheduling interval. The bid structure varies by market product and ISO, but the core components are similar: a megawatt quantity, a price (in $/MWh for energy, or $/MW for capacity products), and performance characteristics like ramp rate and minimum run duration.
Day-ahead bids are submitted 24 hours before the operating day and are cleared against the day-ahead LMP forecast. If a DER aggregation clears day-ahead, it is scheduled for that position and receives the day-ahead LMP for cleared energy. Real-time deviations from the day-ahead schedule are settled at the real-time LMP, which may be higher or lower depending on actual system conditions.
For ancillary service markets, bids take a slightly different form. A regulation up/down bid specifies the symmetric or asymmetric MW capacity that the aggregation can provide in response to the ISO's automatic generation control (AGC) signal. A spinning reserve bid specifies the MW that can be delivered within 10 minutes. Each product has different capability requirements that the aggregation must demonstrate through testing before it can offer those products.
The bid stack construction is where dispatch optimization connects to market participation. To submit a competitive day-ahead energy bid, you need a forecast of the aggregate's available capacity for each hour of the next day, a view on expected LMPs, and a model of the constraints on each underlying asset that limit what the aggregate can commit. A battery that is already committed to providing regulation cannot simultaneously provide all its capacity as energy. The bid stack needs to reflect these joint constraints across market products.
Settlement and Imbalance Charges
Settlement in ISO wholesale markets works through a two-settlement system for energy. Day-ahead cleared positions are settled at day-ahead LMP. Deviations between day-ahead schedule and real-time actuals are settled at real-time LMP, with deviations in the direction that hurt the system (increasing load when prices are high, or reducing generation when prices are high) incurring imbalance charges.
For a DER aggregation, the settlement calculation is straightforward in principle but complex in practice. Each individual resource in the aggregation has its own metered data, which must be aggregated and reported in a way that the ISO can match to the registered aggregation entity. If the aggregation spans multiple distribution feeders, multiple distribution utility service territories, or multiple load serving entities, the metering and data flow can involve several different parties.
Imbalance exposure is the primary financial risk in wholesale market participation. An aggregation that consistently under-delivers relative to its day-ahead schedule in high-price intervals incurs settlement charges that can wipe out the revenue from cleared day-ahead positions. This is why load forecasting accuracy at the aggregate level directly translates to P&L. A 5% under-delivery in a high-price interval is not just a missed revenue opportunity: it is a charge at real-time LMP for the shortfall.
The Distribution Utility Interaction
One of the less-discussed operational complexities in DER aggregation is the interaction with the underlying distribution utility. The ISO interacts with the aggregation as a transmission-level entity, but the physical assets are distributed across the distribution system. The distribution utility is responsible for maintaining distribution reliability and has visibility and authority over what happens on its feeders.
FERC Order 2222 required ISOs to establish distribution utility notification and coordination procedures. In practice, this means the aggregator must notify the distribution utility of its planned dispatch schedule and must be prepared to modify dispatch in response to distribution constraints if the utility identifies a reliability issue. This two-layer coordination between ISO dispatch signals and distribution operator constraints is real and can create situations where the aggregation cannot fully perform as scheduled in the ISO market because a local feeder constraint intervenes.
Operators entering wholesale markets for the first time are sometimes surprised by this interaction. They assume that clearing a day-ahead market bid is equivalent to having permission to dispatch. In practice, distribution operator coordination is a concurrent obligation, and the dispatch optimizer needs to have awareness of distribution constraints that might limit the available capacity of assets on specific feeders.
Where ISO Implementations Stand Today
CAISO has the most mature DER aggregation tariff in the country, including the Proxy Demand Resource (PDR) and Reliability Demand Response Resource (RDRR) constructs. PJM's wholesale DER aggregation rules are in place but have seen relatively limited participation from small DER operators due to metering and telemetry cost barriers. MISO and SPP have made more incremental progress. NYISO and ISO-NE have implemented their Order 2222 compliance filings but the tariff products are newer.
We are not saying the markets that have full tariff compliance are easy to navigate. Each ISO has its own registration process, its own telemetry specifications, and its own settlement calculation methodology. An aggregator operating in multiple ISO territories needs to maintain separate registration, telemetry feeds, and settlement reconciliation processes for each. The software infrastructure to manage this is non-trivial and is one of the operational barriers that still limits the scale of DER wholesale market participation relative to the total installed DER capacity.
The operational path from "I have distributed batteries and flexible loads" to "I am a registered ISO market participant" involves telemetry buildout, registration paperwork, capability testing, and bilateral coordination with distribution utilities. Each step has lead time. For operators considering this path, the planning horizon for first market participation from scratch is typically six to twelve months depending on ISO and asset type.