Unlocking Revenue: Generac's New DER Program

Your industrial facility is likely sitting on thousands of dollars in unrealized value right now. The generators, batteries, and controllable loads that run your operations don't have to be single-purpose assets — they can be dispatched to support the grid during high-demand periods, and you get paid for it. That's the core logic behind the new partnership between Generac and CPower, and for commercial and industrial customers across the PJM Interconnection, it represents a genuinely significant financial opportunity.

What Distributed Energy Resources Mean for Your Bottom Line

Distributed energy resources — DERs — is the industry's umbrella term for the decentralized assets that can either generate, store, or shift electricity consumption: rooftop solar, battery systems, backup generators, EV chargers, HVAC controls. Individually, they're useful. Aggregated and coordinated intelligently, they become a grid resource that system operators will pay for.

The business case for DER participation isn't theoretical — it's measurable in dollars per megawatt per day.

PJM, the regional transmission organization managing the grid across 13 states plus Washington D.C., is the largest wholesale electricity market in the country. It serves roughly 65 million people. When Generac and CPower say their new program covers the PJM Interconnection, they're talking about reaching a substantial slice of American commercial and industrial energy users — facilities in Pennsylvania, Ohio, Illinois, New Jersey, Virginia, and beyond.

The Generac-CPower Collaboration

Generac is widely known for its backup power products — the generators humming behind hospitals, data centers, and manufacturing plants. CPower is a different kind of company: a demand response and virtual power plant (VPP) aggregator that manages customer assets on behalf of grid operators. They currently have 6.7 GW of customer capacity under management. For context, that's more generation capacity than many mid-sized utilities.

The partnership works by layering CPower's software platform on top of Generac's installed customer base. C&I customers who already own Generac assets — generators, battery storage systems — can now enroll in programs that compensate them for making those assets available to the grid during critical periods. The programs span capacity markets, ancillary services, energy markets, and on-bill savings initiatives, all within the PJM structure.

This isn't a future pilot program. It's available to customers now.

Breaking Down the Numbers

The financial mechanics here deserve a close look because the capacity charge structure in PJM is one of the least understood — and most consequential — cost drivers for large energy users.

Large industrial customers are billed based on something called their peak load contribution (PLC). This is a measurement, in megawatts, of how much load a facility is expected to draw during the five highest-demand hours of the entire year across PJM. The tricky part: those five hours are only identified after the fact. That means facilities are essentially charged all year long based on what they consumed during a handful of summer afternoons.

For the 2026/2027 delivery year, PJM's capacity clearing price is $329.17 per MW per day. Run that math: a facility with a PLC of 5 MW is paying over $600,000 annually in capacity charges alone — before touching a single kilowatt-hour of actual energy consumption. Shaving even half a megawatt off that PLC through strategic demand response could mean $60,000 or more in annual savings. That's not a rounding error. That's a line item that changes project economics.

Beyond PLC management, assets dispatched into ancillary services markets — things like frequency regulation, which requires rapid response to grid fluctuations — generate direct revenue payments. As Russ Newbold, CPower's VP of distributed generation growth, noted: "Assets may be compensated in different ways because generators, batteries, and load may each provide value to the grid in different programs." Batteries, for instance, excel at short-duration ancillary service dispatches precisely because they respond in milliseconds. Diesel generators are better suited for longer-duration capacity events. A well-structured DER program optimizes across all of them.

How Demand Response Works When It Gets Dispatched

The mechanics of demand response are simpler than the jargon suggests. When grid stress reaches a threshold — high temperatures driving air conditioning loads, an unexpected generation outage, a surge in industrial activity — CPower's platform sends dispatch signals to enrolled facilities. Those facilities either curtail their consumption, fire up backup generation, or discharge stored energy. The result is a reduction in net grid demand at precisely the moment the grid needs it most.

CPower reported delivering 38 GWh of total load relief to the grid in 2025. That's a 137% increase over 2024 — a number that reflects both portfolio growth and more frequent dispatch events as grid stress has intensified. To put 38 GWh in perspective, that's roughly the annual electricity consumption of 3,500 average American homes, delivered as relief at critical moments rather than as generation from a power plant.

What makes this arrangement strategically valuable is that grid operators get dispatchable capacity without building new infrastructure, and customers monetize assets they already own.

The insider reality is that most C&I facilities are already operating assets — generators, batteries — in a fundamentally passive way. They sit idle, maintained at a cost, waiting for an outage that may never come. Demand response enrollment doesn't meaningfully change operational risk for most facilities; those assets remain available for their primary function. What changes is that the idle time between uses becomes a revenue opportunity.

The Broader Shift This Partnership Represents

Newbold framed the partnership in terms that go beyond the balance sheet: "This partnership is a real-world example of how distributed generation and demand response can be mobilized today to help address rising demand and affordability pressures without waiting for large-scale transmission expansion."

That's a pointed observation. New transmission infrastructure in the U.S. takes a decade or more to permit, finance, and build. Grid demand is growing now — driven by data center build-out, industrial electrification, and EV adoption. Virtual power plants represent one of the few tools that can scale quickly because they're built on assets that already exist.

Wood Mackenzie consistently ranks CPower among the top companies by GW under management in their annual VPP reports. The VPP market is growing fast, but it's still early. Many eligible C&I customers haven't enrolled simply because the programs weren't accessible through their existing equipment vendors. Embedding CPower's platform into Generac's customer relationships removes that friction.

For commercial and industrial energy managers evaluating their options: the question is no longer whether to participate in distributed energy programs, but how quickly you can assess your existing asset portfolio and calculate what participation is worth. The PLC season runs every summer. The 2026 coincident peaks will determine capacity charges that follow customers through 2027 and beyond. The time to act on that math is now.

Explore more about how to unlock your revenue potential with Generac and CPower.

[INTERNAL LINK: DER programs]

[INTERNAL LINK: demand response]

[INTERNAL LINK: virtual power plants]