Commercial building operators sit on a substantial and largely untapped grid resource. The aggregate controllable load in mid-to-large commercial buildings — HVAC, lighting, plug loads, EV charging, refrigeration — represents hundreds of megawatts of dispatchable demand flexibility in any major metro area. ISOs and utilities have built market structures to compensate this flexibility, but enrollment complexity and minimum capacity thresholds have historically kept smaller commercial portfolios from participating. That barrier is lower than it used to be, and the revenue opportunity is real enough to justify serious attention.
This article covers how demand response programs are structured across the major ISO markets, what the payment mechanics actually are, what the operational obligations mean for a building that enrolls, and where the practical difficulties lie — because there are genuine difficulties that program brochures don't dwell on.
The Basic Market Structure
Demand response (DR) in ISO markets operates across three distinct program types, each with different compensation structures, commitment levels, and dispatch characteristics. Understanding which program fits which building type is the starting point.
Capacity Market DR (PJM Example: Emergency Load Response and Capacity Performance)
PJM's capacity market (RPM — Reliability Pricing Model) allows demand resources to participate as capacity, offering to reduce load during grid emergency conditions. The baseline compensation is a capacity payment per kW-year for the committed demand reduction, awarded through PJM's Base Residual Auction (BRA) and incremental auctions. Clearing prices for demand resources in PJM have ranged widely — from roughly $16/kW-year in low-stress auction years to over $150/kW-year in the 2025/2026 delivery year auction, which cleared at elevated prices due to accelerating data center load growth across PJM's footprint.
The obligation under Capacity Performance (CP) rules is strict: enrolled resources must respond to emergency dispatch events with high reliability, or face performance penalties that can exceed the capacity payment received. A resource that misses a dispatch event can owe back its capacity payment plus a penalty multiplier. This performance risk is the reason that serious DR aggregators do extensive pre-enrollment verification — they only enroll buildings they're confident will actually curtail reliably.
Energy Market DR (Real-Time and Day-Ahead)
FERC Order 745, issued in 2011 and upheld by the Supreme Court in 2016, required ISOs to compensate demand response resources for energy reductions at the full Locational Marginal Price (LMP) when those reductions are cost-effective. This means a building that reduces 100 kW of load during a period when the LMP at its delivery point is $85/MWh receives $8.50 in that hour — the same rate a peaking generator would receive for producing 100 kWh. In high-stress hours during summer peaks, LMPs in constrained PJM zones have reached $200–$500/MWh, making energy market DR payments significant.
The practical constraint on energy market DR is the notification timeline. Day-ahead market DR requires the aggregator to submit curtailment offers by 10:30 AM for the following operating day. Real-time market DR is dispatched with shorter notice — as little as 10–30 minutes in most ISO protocols. Building loads that require occupant notification, operator approval, or slow-ramp HVAC adjustments struggle with short notification windows. The DR resources that capture real-time market revenue reliably are those with fast-acting, automated curtailment that can execute within the notification window without manual intervention.
Ancillary Services DR
Some ISOs — notably PJM and ERCOT — allow demand resources to provide regulation and spinning reserve ancillary services. Regulation service requires a resource to follow an automatic generation control (AGC) signal, modulating output up and down continuously over the operating hour. For a building BESS or a large commercial chiller with VFD, this is technically achievable, but the mileage payments and the 100% availability obligation during committed hours require automation infrastructure that few commercial buildings have deployed as of 2025.
The regulation market opportunity is real — PJM regulation clearing prices have reached $30–$50/MW-hour in summer periods — but we're not saying this is accessible to most commercial building operators today. The infrastructure requirement (sub-minute telemetry to the ISO, automated dispatch control, performance monitoring) is currently more commonly implemented by C&I aggregators with dedicated control systems than by individual building BMS platforms.
The ERCOT Picture: Simpler Structure, Different Risks
ERCOT operates without a traditional capacity market, relying instead on a high-price energy market to signal scarcity. This means demand response in Texas earns primarily through the real-time energy market (RTLMP) during high-stress hours — which can be very high. During ERCOT's winter storm events and summer peak periods, RTLMPs have reached the $9,000/MWh market cap. A building with 200 kW of curtailable load that curtails for four hours at even $500/MWh average LMP earns $400 in those four hours.
ERCOT's Emergency Response Service (ERS) program compensates load that can shed within 10 minutes of a grid emergency at a fixed quarterly payment, independent of energy market prices. ERS has four contract windows per year, with typical compensation around $5–$8/kW-quarter for 10-minute response capability. For buildings with interruptible loads and fast-acting control systems, ERS provides baseline revenue with defined obligation windows (ERS contracts specify exactly which hours the load must be available).
Enrollment Mechanics and the Aggregation Model
Most commercial buildings enroll in DR programs through a third-party aggregator — a Curtailment Service Provider (CSP) in PJM parlance, or a Qualified Scheduling Entity (QSE) in ERCOT. The aggregator handles the ISO interface: bid submission, telemetry requirements, metering certification, and settlement reporting. The building operator signs a Demand Response Service Agreement (DRSA) that specifies the enrolled capacity, curtailment obligations, dispatch notification timeline, and revenue sharing terms.
Revenue sharing structures vary significantly. Aggregators typically take 15–30% of capacity payments and energy market revenues in exchange for handling program administration and performance risk management. Some aggregators offer a fixed per-kW incentive rather than revenue sharing, which can be attractive for buildings with uncertain performance profiles. The enrolled capacity figure is critical — it's based on a metered baseline methodology that calculates the building's expected consumption absent curtailment, against which actual curtailment is measured. PJM uses a 10-of-10 baseline (average of the 10 highest consumption hours in the prior 90 days) with adjustments for weather. ERCOT uses a 60-day rolling baseline. Baseline methodology matters because it determines how much of a curtailment event counts as delivered capacity.
What "Curtailment" Actually Requires from the Building
This is where DR program participation often fails in practice. A building that signs an enrollment agreement based on nominal 200 kW curtailment capacity may discover during its first dispatch event that achieving 200 kW of verified reduction is harder than expected.
Consider a 12-story Class A office building in a PJM-East zone — 350,000 sq ft, peak demand around 1,100 kW. The building operator enrolls 150 kW of curtailment based on HVAC setpoint flexibility: raising cooling setpoints 2°F during dispatch events. During the summer testing period, a dispatch event occurs on a 94°F afternoon. The building's baseline calculation shows expected consumption of 980 kW for that hour. The operator raises cooling setpoints and achieves actual consumption of 855 kW — 125 kW of reduction, not 150 kW. The shortfall triggers a performance penalty under CP rules. The root cause: the building's cooling load at 94°F is higher than in the baseline sample, so the 2°F setpoint change delivers less absolute kW reduction than on a cooler day.
This is the baseline-curtailment correlation problem that trips up many first-year DR participants. Curtailment depth varies with weather, occupancy, and building state. A static curtailment strategy — always raise setpoints 2°F — produces variable kW reductions, which creates performance uncertainty against a fixed enrolled MW commitment.
FERC Order 2222 and Distributed Resource Aggregation
FERC Order 2222, finalized in 2020, directed ISOs/RTOs to remove barriers to distributed energy resource (DER) aggregation in wholesale markets. The practical impact for commercial buildings is that small DERs — behind-the-meter batteries, EV charging stations, small generators, controllable loads below the traditional ISO minimum participation threshold of 100 kW — can be aggregated with neighboring resources to meet participation minimums and access capacity and energy market revenue streams.
ISO implementation timelines for Order 2222 compliance have varied. PJM published its compliance tariff revisions in phases through 2023–2024. MISO and SPP continue their compliance implementation processes as of 2025. The significance for commercial building operators is that buildings previously too small to participate directly — a 50,000 sq ft retail center with 120 kW peak demand — may become eligible as part of an aggregated DER portfolio managed by an Order 2222-compliant aggregator. The enrollment paperwork and metering requirements are handled at the aggregator level.
Program Stacking: The Advanced Play
For commercial buildings with multiple controllable assets — BESS, EV charging, large HVAC, process loads — the highest-value DR strategy involves stacking multiple program revenues simultaneously. A building BESS enrolled in PJM's Capacity Performance program earns capacity revenue for its curtailment capability; in non-dispatch hours, the same BESS participates in the regulation market, earning mileage payments for AGC signal following. The thermal load flexibility provides backup curtailment capacity for CP dispatch events when the BESS is partially discharged from regulation service.
Program stacking requires careful attention to availability conflicts — a BESS cannot simultaneously provide spinning reserve (which requires it to hold charge) and provide regulation down service (which may require it to discharge). Aggregators with experience in multi-service optimization manage these conflicts through real-time portfolio dispatch algorithms, but the building operator should understand the tradeoffs before committing to stacked enrollment contracts with overlapping availability windows.
The economics of well-executed program stacking across a 500 kW commercial BESS in a high-value PJM zone — combining capacity market revenue, regulation market mileage, and energy market price arbitrage — can reach $80,000–$150,000 per year in favorable auction and market conditions. That's a material contribution to BESS project economics and, in many cases, the difference between a project that pencils out on demand charges alone versus one that provides a clear 5-year payback on the full BESS capital cost.
The Operational Commitment That Programs Require
Commercial building operators who treat DR program enrollment as a passive revenue stream — sign the contract, collect the check, ignore the dispatch events — consistently underperform and face penalties. The buildings that perform well year after year invest in three things: real-time interval metering at the enrolled meter point (revenue-grade AMI, not just the BMS trend data); automated curtailment controls that execute on dispatch signals without manual intervention; and ongoing baseline monitoring so that enrolled capacity reflects what the building can actually deliver, not what it could deliver under ideal conditions when the contract was signed.
DR programs are a grid resource, not a building efficiency retrofit. The grid needs to rely on that capacity when it's dispatched. Buildings that engineer their curtailment capability seriously — and automate the dispatch execution — capture the full revenue opportunity. Buildings that treat it as an occasional manual procedure find the performance penalties eroding the capacity payments.