Demand Response Programs for Cannabis Facilities

What demand response is and who actually pays you

Demand response is a payment for not using electricity at a specific time. PJM describes it as the way retail customers "can respond to wholesale electricity prices or to reliability needs of the system" and get paid through the wholesale energy, capacity, and ancillary services markets for reducing demand [pjm-dr-fact-sheet]. The grid operator or utility needs load to disappear for a few hours on a hot afternoon or during an emergency, and it is cheaper to pay you than to build a peaker plant.

There are two pots of money, and it helps to keep them separate.

ISO and RTO market programs. In PJM, ISO New England, NYISO, CAISO, and ERCOT, the wholesale market itself buys curtailment. PJM runs two categories: Load Management, where "providers make a commitment in the capacity market to reduce load when required by the system or receive a financial penalty," and Economic DR, where customers "participate in the energy and ancillary services markets when it is economic for them" [pjm-dr-fact-sheet]. You do not deal with PJM directly. Curtailment Service Providers "aggregate customers' curtailment capability, register that capability with PJM, offer it in the appropriate market, submit load data to verify the reductions and receive payment from PJM," and the split between the CSP and you "is a matter of private agreement" [pjm-dr-fact-sheet].

Utility programs. The distribution utility runs its own programs, often to relieve a specific substation or network. Con Edison's Commercial System Relief Program and Distribution Load Relief Program are examples, and they pay per kW reserved per month plus per kWh during events [coned-smart-usage-rewards]. These stack with ISO programs in some territories and exclude them in others, so the enrollment rules matter.

A grow is a large, predictable load with an interval meter, which is exactly what an aggregator wants to enroll. The question is what part of it you can actually shed.

What a grow can realistically curtail

Lighting is roughly two thirds of an indoor facility's electricity, and flowering rooms alone were 49 percent of use in the Northwest Power and Conservation Council's producer survey, with cooling around 15 percent and dehumidification most of the rest [nwpcc-cannabis]. A flowering room mid-photoperiod is not curtailable. Cutting the lights for four hours costs more in yield than any program pays. So the honest answer to "how much can we shed" starts by removing the lit canopy from the table.

What is left is more than most owners expect:

The single biggest lever is room scheduling. A facility that staggers photoperiods, which we recommend anyway for demand charges, always has roughly half its canopy dark. During a 2 p.m. to 6 p.m. summer event, the dark rooms' HVAC and dehumidification can be relaxed, the lit rooms can be pre-cooled, and the drying rooms can pause. For many facilities that adds up to 10 to 25 percent of peak demand; the exact number comes from your interval data and a walk-through with your controls integrator, not from a rule of thumb.

The ISO programs, region by region

PJM (Illinois, Ohio, Pennsylvania, New Jersey, Maryland, Delaware, D.C., and parts of Michigan)

Most PJM demand response money is in the capacity market, the Reliability Pricing Model, where demand response "may receive payments for committing to reduce electricity demand up to three years in the future" [pjm-dr-fact-sheet]. Load Management resources are dispatched by PJM as Pre-Emergency or Emergency load reductions, and the dispatch instructions are posted with defined lead times; PJM's operating guidance includes a 30-minute notification exception, which tells you standard lead times are longer [pjm-dr-page]. The commitment is firm: "DR participants must reduce load when requested by PJM or receive a significant financial penalty" [pjm-dr-fact-sheet]. Economic DR is the softer option. Your CSP offers your reduction into the day-ahead or real-time energy market and it clears "in the same way as a generator" when your offer price is below the marginal price [pjm-dr-fact-sheet]. Nothing happens if prices stay low.

ISO New England (Massachusetts, Connecticut, Rhode Island, New Hampshire, Maine)

ISO-NE treats demand resources as "competitive assets that help meet New England's electricity needs," participating through a price-responsive demand structure that took effect June 1, 2018 [isone-demand-resources]. Individual demand response assets need at least 10 kW, smaller assets are aggregated into demand response resources of at least 100 kW, and resources are dispatched when wholesale prices reach their offer [isone-newswire-dr-faq]. In 2023 New England had about 436 MW of demand response capacity, and 88 percent of resources offered at 1,000 dollars per MWh against an average real-time price of 35.70 dollars, meaning most only expect to be called in genuine scarcity [isone-newswire-dr-faq]. Capacity revenue comes through the Forward Capacity Market for resources that take on a capacity supply obligation.

CAISO (California)

California's demand response is split between utility-administered programs, community choice aggregators, and third-party demand response providers [cpuc-dr-page]. Third-party DRPs operate under Rule 24 (PG&E and SCE) or Rule 32 (SDG&E), register with the CPUC, and bid customers' load reductions into CAISO, a practice called direct participation; a customer generally cannot be enrolled with a DRP and a utility program at the same time [cpuc-drp-faq]. The Demand Response Auction Mechanism, DRAM, was the CPUC's pilot for procuring resource adequacy from those third parties, and the Commission opened a new rulemaking on September 29, 2025 (R.25-09-004) to redesign demand response going forward [cpuc-dr-page], so ask any California aggregator which vehicle they are actually using this year.

The utility programs are concrete. PG&E's Base Interruptible Program requires 100 kW or more of maximum demand, pays monthly capacity payments, and charges 6 dollars per kWh for usage above your firm service level during an event, with events capped at six hours, ten per month, and 180 hours per year [pge-business-dr]. The Capacity Bidding Program is aggregator-managed, runs May 1 through October 31, has no minimum demand, and caps events at four hours [pge-business-dr]. The Emergency Load Reduction Program pays 2 dollars per kWh reduced, requires only 1 kW of reduction and an interval meter, runs May 1 through October 31 between 4 p.m. and 9 p.m., and has "zero penalties if you can't participate" [sce-elrp]. For a grow that cannot commit firm load, ELRP is the obvious entry point.

ERCOT (Texas)

ERCOT-administered demand response is mostly Load Resources in ancillary services and the Emergency Response Service, and the four transmission and distribution utilities run summer load management programs on weekdays from June 1 through September 30 between 1 p.m. and 7 p.m. [ercot-dr-overview-2023]. The bigger Texas lever is not a program at all. Transmission cost is allocated by your load during the four coincident peaks, "the highest-Load 15-minute settlement intervals in each of the four summer months," and ERCOT estimated 1 MW of 4CP reduction was worth about 38,000 dollars a year for a transmission-connected customer on Oncor's system [ercot-dr-overview-2023]. See peak demand vs. peak usage for how 4CP works.

New York (NYISO plus utility programs)

Con Edison's Commercial System Relief Program pays a reservation payment of 18 dollars per kW per month in Brooklyn, the Bronx, Manhattan, and Queens, or 6 dollars per kW per month in Staten Island and Westchester, plus 1 dollar per kWh during events, with 21 hours' notice and an 11 a.m. to 11 p.m. event window on weekdays [coned-smart-usage-rewards]. The Distribution Load Relief Program pays 18 or 25 dollars per kW per month depending on network tier, with two hours' notice or less and an 8 a.m. to midnight window, seven days a week [coned-smart-usage-rewards]. Con Edison's own framing is that participants can "earn up to 18,000 dollars a year for every 100 kilowatts" reduced, and enrollment is through an aggregator or direct [coned-smart-usage-rewards]. Upstate utilities run similar programs with their own rates.

How aggregators get paid and what to ask them

In PJM the CSP receives the market payment and pays you under a private contract [pjm-dr-fact-sheet]. In California, DRPs bid your load into CAISO and need your signed data-sharing authorization to pull your interval data [cpuc-drp-faq]. The commercial model is almost always a revenue share: the aggregator keeps a percentage, often somewhere between a quarter and half, in exchange for handling registration, baselines, dispatch notification, and settlement.

Questions to ask before you sign:

1. Which programs, specifically, and which is firm versus voluntary? A PJM capacity commitment carries a penalty [pjm-dr-fact-sheet]; ELRP does not [sce-elrp].
2. What kW will you nominate for me, and how did you calculate it from my interval data?
3. What is the revenue split, and is there a minimum payment if no events are called?
4. Does the event window overlap my dark periods, and can I override during a critical crop stage?
5. How long is the term, and what happens at renewal? See the contract terms page for the clauses that bite.

A worked example

Every number below is an input we chose to show the arithmetic. Replace them with your own.

Assume a facility with a 550 kW summer peak, four flower rooms on two staggered photoperiods, so two rooms are always dark, and a 300 kW dark-period load made up of HVAC, dehumidification, drying rooms, and support equipment. Say the controls integrator confirms you can shed 90 kW of that for four hours by widening dark-room setpoints, pausing drying-room dehumidifiers, and pre-cooling the lit rooms.

Scenario A: a utility reservation program. Take Con Edison's CSRP rate of 18 dollars per kW-month in the four boroughs for the five-month capability period [coned-smart-usage-rewards]. Reservation: 90 kW × 18 dollars × 5 months = 8,100 dollars. Add performance payments of 1 dollar per kWh: 90 kW × 4 hours × 5 events = 1,800 dollars. Total about 9,900 dollars a year before the aggregator's share. At a 30 percent split you keep roughly 6,900 dollars.

Scenario B: a voluntary pay-per-event program. Under ELRP's 2 dollars per kWh [sce-elrp], the same 90 kW over 5 events of 4 hours pays 90 × 4 × 5 × 2 = 3,600 dollars, and zero in a mild summer with no events. There is no penalty for missing an event [sce-elrp], so a facility in a sensitive crop stage can simply sit one out.

Neither number changes your business, but both are close to free money for a facility that already has the controls to manage its peak demand. The larger value is often the discipline it creates: once you know which 90 kW you can drop on command, you also know which 90 kW is setting your demand charge every month.

Skip it if every room is lit during the event window, if the program is firm and your crop cannot tolerate a 2 degree drift, or if the aggregator wants to nominate lighting load. Otherwise, pull the interval file and have the conversation.