Community solar programs are primarily thought of as generation-side programs — subscriber accounts receive credits for solar output, and program economics are driven by generation capacity and subscriber enrollment. But community solar programs also manage load: subscriber accounts aggregate significant flexible load capacity in the form of water heaters, HVAC systems, EV chargers, and in some programs, thermostat-controlled building systems. This load flexibility, accessed through the same VPP infrastructure used for solar and storage dispatch, can generate a second revenue stream from demand response and load flexibility programs — alongside capacity market participation.
This post explores what load flexibility programs are available to community solar operators, how they integrate with capacity market VPP operations, and where the revenue opportunity is realistic versus overstated.
Demand Response Programs: The Available Structures
In PJM, ISO-NE, and NYISO territory, demand response programs take several forms that community solar operators should understand:
- Emergency Demand Response: Programs activated during grid emergencies or price spikes. PJM's Emergency Load Response Program (ELRP) and ISO-NE's Real-Time Demand Response program fall in this category. Activation events are infrequent (typically 5-20 times per year) but compensation rates during emergency events can be high.
- Economic Demand Response: Participants reduce load when real-time energy prices exceed their offer price threshold. PJM's Economic Load Response and NYISO's Day-Ahead Demand Response Program allow load reductions to be bid into the day-ahead market as supply-side resources. Revenue is more predictable than emergency DR but requires more active offer management.
- Capacity-Committed Demand Response: Load reductions committed in the capacity market as capacity resources. This is the closest structural analog to capacity market participation by generation resources — the demand response provider holds a capacity obligation and is dispatched during Performance Assessment Intervals.
- Utility DR Programs: Distribution utility-operated programs that pay for load reduction at the distribution level, independent of ISO market participation. These are often simpler to access than ISO programs but offer lower compensation rates.
What Load Assets Community Solar Programs Can Access
Community solar programs with residential subscriber bases typically have access to thermostat-controlled HVAC loads (via smart thermostat enrollment programs), water heater thermal storage, and EV charging load. Programs with commercial and industrial subscribers have access to more substantial flexible loads — commercial HVAC, lighting controls, industrial process loads — which carry higher per-MW flexibility value.
The effective flexible load capacity in a residential community solar program varies considerably by subscriber demographics and geography. A program in a warmer climate with a high density of residential air conditioning has more HVAC flexibility value in summer peak periods than a program in a temperate climate. A program with commercial subscribers who have submetered flexible load has a more predictable flexibility profile than one composed entirely of residential accounts.
Estimating the flexible load capacity available from a subscriber base requires actual load profile analysis — looking at subscriber interval data to identify the typical peak demand per account and the historical load reduction potential from curtailment. Programs that haven't done this analysis tend to either overestimate their DR capacity (by assuming all subscriber load is equally flexible) or underestimate it (by excluding flexible load they didn't realize existed in their portfolio).
Integration with Capacity Market VPP Operations
The operational case for combining load flexibility with capacity market VPP infrastructure is that the two programs share much of the same technical stack. A community solar program that has already built the asset registry, telemetry normalization, and dispatch management infrastructure for ISO capacity market participation is well-positioned to extend that infrastructure to include load assets without rebuilding from scratch.
The incremental technical requirements for adding load flexibility to an existing capacity market VPP are: (a) asset registration for the load devices (smart thermostats, EV chargers, hot water controllers) in the aggregation platform's registry; (b) a dispatch channel to the load control devices — typically through a device API or aggregated through a third-party home energy management system; and (c) metering of the load reduction during DR events, either from the same AMI meter used for generation settlement or from submeters on the controlled load circuits.
The dispatch channel to load devices is often the limiting technical factor. Smart thermostat platforms (Nest, Ecobee, and similar) have utility program APIs that allow aggregated dispatch — but accessing these APIs for ISO DR purposes requires program agreements and in some cases utility approval. EV charger management APIs vary considerably across charger manufacturers. Programs that want to aggregate load flexibility should expect an 8-12 week integration effort per device platform to establish the dispatch channel and test it under DR event conditions.
Revenue Sizing: Realistic Expectations
Community solar operators evaluating load flexibility as a revenue stream sometimes receive projections that don't survive contact with program reality. A few calibrating points:
Emergency demand response revenue is highly event-dependent. In a year with few emergency events, compensation may be modest. In a year with multiple extreme weather events, the same program earns substantially more. Programs should model DR revenue on a conservative expected-events basis rather than on peak-event assumptions.
Residential load flexibility per account is typically in the range of 0.5-2 kW per account, depending on home size, equipment, and climate. A 1,000-subscriber community solar program with residential load flexibility might have 500 kW to 2 MW of flexible load capacity — meaningful but not dominant relative to a solar and storage capacity market commitment in a similarly-sized program.
We're not saying load flexibility is not worth pursuing. For programs that already have the VPP infrastructure in place, the incremental revenue from DR participation relative to the incremental cost of adding load assets is generally positive. The programs that have been disappointed by DR revenue are typically the ones who treated load flexibility as a primary revenue strategy rather than a secondary revenue stream layered on top of capacity market participation.
Co-Optimization: When Capacity and DR Compete
Community solar programs that hold both ISO capacity commitments and demand response obligations need a co-optimization strategy for dispatch events that could call on the same assets. A storage battery that's dispatching for an ISO capacity event shouldn't simultaneously be reducing load for a utility DR event — but without explicit co-optimization logic, a naive dispatch system might attempt exactly that.
The co-optimization problem is most acute during summer peak periods, when both capacity Performance Assessment Intervals and demand response emergency events are most likely. The aggregation platform needs to maintain a dispatch priority order — typically ISO capacity obligations rank above utility DR programs — and reserve the capacity needed for each obligation before dispatching for lower-priority programs.
Programs that have designed their load flexibility program alongside their capacity market participation — rather than adding DR as an afterthought — handle co-optimization cleanly because the asset categorization (which assets are available for which programs) is established before dispatch events occur. Programs that added DR to an existing VPP without updating the dispatch logic sometimes discover the co-optimization problem during their first simultaneous DR and capacity event, which is not the ideal time to debug it.
State Program Incentives and Load Flexibility
Several states with active community solar programs offer incentive payments for load flexibility programs that layer on top of ISO DR compensation. Maryland's EmPOWER program, Massachusetts's ConnectedSolutions, and similar state-level efficiency and flexibility programs provide additional revenue streams for programs that can document verified load reductions. These state programs often have less technical complexity than ISO market participation — simpler telemetry requirements, less stringent dispatch test requirements — and can be a reasonable starting point for programs that haven't yet completed ISO capacity enrollment but want to begin capturing flexibility value from their subscriber load.
The operational experience from state DR programs also provides useful preparation for ISO capacity market dispatch operations. Programs that have managed DR events — tracking response, documenting performance, resolving telemetry issues — arrive at ISO capacity market participation with a more realistic understanding of what dispatch operations require than programs that are encountering it for the first time.