By Jason Guck, Delta Edge CI
Demand response is the one energy program where the utility pays you for something you already control. You agree to reduce load when the grid is tight, and you get compensated for being willing and, separately, for actually doing it. For some operators that is a straightforward addition to the bottom line. For others it is a commitment they should not sign.
The interesting evidence that this is not a simple yes or no is that two neighboring wholesale markets are moving in opposite directions. According to FERC’s most recent annual assessment, registered demand response in PJM fell by roughly 1,141 megawatts, about 11 percent, between 2023 and 2024. Over the same period NYISO’s demand response registration rose by about 212 megawatts, roughly 12 percent. Same technology, same era, adjacent geography, opposite trend.
Program design explains most of that divergence, and program design is exactly what an operator has to read before enrolling.
Two Different Things Get Called Demand Response
Confusing them is the most common reason a program disappoints.
Capacity or reliability programs
You are paid to be available. The payment arrives whether or not you are ever called. In exchange you commit to a specific reduction, within a specific notification window, for a specific number of hours, and you are penalized if you fail to deliver when called. In PJM’s Load Management and NYISO’s reliability programs, this is the bulk of the enrolled megawatts. The revenue is predictable. The obligation is real.
Economic or energy programs
You are paid only when you curtail, based on the market price at that moment. There is no availability payment and usually no penalty for declining. The revenue is unpredictable and depends on volatility. NYISO’s Demand-Side Ancillary Service Program and PJM’s Economic program sit here. FERC’s figures show PJM’s Economic participation falling 300 megawatts while Load Management fell 789, so both categories moved together there, but they behave very differently for a single operator deciding what to sign.
The practical difference: a capacity program is a contract with a performance obligation. An economic program is an option you can decline. Operators who want certain revenue take the first and then discover the obligation. Operators who want no obligation take the second and then discover the revenue was small.
What You Are Actually Selling
You are not selling electricity. You are selling operational flexibility, and the price you should accept depends entirely on what that flexibility costs you.
A refrigerated warehouse with thermal mass in the product can often ride through a two hour curtailment with no measurable effect, because the building itself is the battery. A plating line cannot pause mid-process without scrapping work. An office tower can raise setpoints three degrees on a summer afternoon and take a handful of complaints. A hospital cannot. Two facilities with identical peak demand can have curtailment costs that differ by an order of magnitude, and the program payment does not care.
So the question is never whether the payment is attractive in isolation. It is whether the payment exceeds the cost of the specific hours you would be asked to give up, at the specific notice you would be given.
When It Is Worth It
- You have genuinely deferrable load. Pre-cooling, thermal storage, non-critical pumping, battery charging, and process steps that can be rescheduled rather than cancelled.
- Your curtailment does not touch revenue. If the reduction comes out of comfort margin or overnight processes rather than production, the cost is close to zero.
- You already know your load shape. Interval data showing where your peaks actually sit, not where you assume they sit.
- You can respond without a person on site. Automated response is more reliable than a phone call to a facility manager who may be off shift.
When It Is Not
- The penalty structure is larger than the upside. Read the non-performance terms before the payment table. In capacity programs this is the whole risk.
- Your plan is to run a generator. Fuel, maintenance, permitting and emissions limits frequently make this uneconomic, and in some programs it is not permitted at all.
- You are enrolling to fix a demand charge problem. These are different mechanisms. Demand response addresses grid events. Demand charges are set by your own monthly peak, and reducing those is a separate exercise, covered in reading your August bill.
- Nobody owns it. A program with real obligations and no named internal owner will eventually be called on a bad day.
What to Do Before You Sign Anything
Pull twelve months of interval data and find the hours the program would most likely call. Those are typically hot weekday afternoons, and they are usually your own peak hours too. Then cost those specific hours: what would this facility have been doing, and what does not doing it cost.
Compare that number against the availability payment plus a conservative estimate of event payments. If the margin is thin, the program is not worth the obligation. If it is wide, the next question is whether your response can be automated, because manual response is where performance penalties come from.
That analysis is the same discipline behind any conservation decision that clears on operating economics rather than capital approval, which is the work we do at Delta Edge CI with commercial and industrial operators. Demand response is worth having in the conversation. It is not worth having by default.
If you are already enrolled, one question is worth asking this week: when were you last called, and did you actually perform, or did you pay the penalty and not notice?