Why GridPoint thinks 13,000 chain-store sites are ready for batteries

GridPoint has set a target of 2GW of distributed battery storage across its existing footprint. That footprint includes pharmacies, restaurants, convenience stores, movie theatres, auto dealerships and retail locations, with brands such as Walgreens, Panda Express and Wendy's on the platform. The company already runs building energy controls at more than 20,000 US commercial sites, and on November 5 it announced that it is adding on-site batteries to that platform. It's starting with roughly 13,000 sites in markets where it says the math already works: California, the PJM grid region (including the Chicago area and New Jersey), and Massachusetts, Rhode Island and Connecticut.

Adrian De Luca, who co-founded GridPoint with Peter Corsell in 2003 and returned this year as CEO after several years in infrastructure investing and climate tech, laid out the plan in an interview with Energy Digital's James Darley. The first projects will range from about 100 to 500 kilowatts. Storage gets added to the existing subscription, which already wraps equipment, installation and nationwide service into one monthly fee, so customers put up no capital.

That changes the question for a facilities director running hundreds of locations. De Luca illustrates it with a chain of 1,000 sites that juggles 5,000 to 10,000 pieces of equipment, every one covered by its own service agreement. Buying a battery the conventional way would put one more contract on that pile. Inside a subscription that GridPoint says already costs most customers less than the savings it creates, nobody is asking for a battery capital request. The decision is which sites qualify.

De Luca's first job at GridPoint was vice president of sales and marketing, and he said that role showed him that strong technology seldom wins a sale by itself. In his view, customers pay for outcomes, and they commit when the decision is easy to make. He is also blunt about the money. Capacity prices won't stay at record highs forever, he says, so GridPoint underwrites on bill savings first and layers grid services on top.

How a store battery pays its way

GridPoint's controls already cut energy spend by actively managing HVAC, refrigeration and lighting, and De Luca put typical customer savings at roughly 20%. The battery stacks on top of that in two ways. The first is a smaller bill. The battery flattens the brief spikes that set a site's monthly demand charge, moves consumption out of expensive peak-rate hours, and discharges during the few grid-wide peak hours that determine a site's capacity and transmission costs for the next year.

That last mechanism is the one most operators underrate, because its value is concentrated in a handful of hours a year. De Luca describes the same hours from the grid's side: when the year's hottest afternoon arrives, he said, the grid will draw on batteries sitting in businesses people go to every day. A store battery that is charged and dispatching on that afternoon earns the lower charge for the following year. One that misses it waits another year.

The second value stream is income: payments from demand response programs, capacity markets and utility programs that reward flexibility. GridPoint says that at qualifying sites, the bill savings and grid revenue combined can lower bills by as much as an additional 15%. Read as simple addition, that puts the best case near 35% off, though the base each percentage applies to isn't specified.

There's a quieter operational point in De Luca's argument. Demand response at stores and restaurants has always run into the same wall: a site can't shut off the walk-in cooler or let the dining room heat up because the grid asked. De Luca called that the main constraint on demand response from commercial sites. A battery lets the site cut what it draws from the grid while the equipment inside keeps running as normal. For chains with heavy refrigeration loads, that's what makes grid programs workable at all.

The outage count in those figures is the other pressure De Luca named. As the grid comes under more strain, he said, resilience matters, and the businesses hosting these batteries are the ones logging those weather-driven outages.

Some rough scale helps here. If the full 2GW were spread across the 13,000 sites in favorable markets, the average would be roughly 150 kW each, by simple division. That's at the low end of the 100-to-500 kW range for initial projects, which fits batteries sized to shave one building's peaks rather than to act as small power plants.

Why California, PJM and three New England states

De Luca told Energy Digital that the economics shifted sharply over the past 18 to 24 months. Equipment costs kept falling. The investment tax credit gave financiers a multi-year window. And stacking bill savings with grid program revenue got easier. Storage was in GridPoint's original vision, he said, and batteries were inside the company's very first products, but GridPoint was early on the economics.

The demand side is moving too. De Luca pointed to US electricity demand on track for records in 2026 and 2027, driven largely by AI data centers and manufacturing. Most battery money so far has gone to utility-scale, large industrial and data center projects, he noted, while millions of commercial buildings sit right where power gets used. His case for those buildings is speed: putting storage in them takes far less time than building new generation or transmission.

PJM, the largest US grid operator, shows the result most clearly: a capacity price at its cap for 2028/2029. For operators in that market, a battery that trims a site's peak demand could reduce their exposure to those capacity costs. Put the rising rates GridPoint sees across its own sites next to that capacity price, and De Luca's framing follows: in his account, rising rates and cheaper batteries have changed the commercial building from something the grid must serve into a resource the grid can call on.

Here's the strongest objection: record capacity prices are exactly the kind of number that doesn't last. De Luca says so himself, and goes further: "Markets will run through boom and bust cycles, and policy will shift." GridPoint underwrites each project on bill savings first and treats grid services as an extra layer. That discipline is the most useful detail in the announcement for a buyer, because it means a site's case has to stand on demand-charge and peak-rate savings even if capacity payments fall back.

The policy half of that warning matters too. The investment tax credit that gave financiers their runway is itself policy, so a case built on bill savings first would also be the sturdier one if that support changes.

It also defines who should pay attention now. For chains concentrated in California, the PJM states or southern New England, the offer is live and specific to individual locations. For chains whose sites sit mostly elsewhere, the announcement is a signal to watch.

Lessons from big batteries that apply to small ones

Big batteries have a few years of hard-won experience with what happens after installation, and some of it applies to small ones. At the 2026 US Battery Asset Management Summit in Garden Grove, California, engineers from AES Corporation and RWE described the gap between a project's commercial operation date and the day it actually earns money, Energy Storage News's April Bonner reported. "COD is not the only important date," said RWE's Grayson Zwingelberg. "Everyone thinks the next day we're making money, that's not what's happening in reality."

Christian Lopez of AES said equipment availability typically climbs over the first 12 months, from 88-90% to 95-98%. Zwingelberg said equipment failures in the first couple of months of commissioning can push revenue back by months, naming stack and chiller failures as problems to plan for because they will happen. His advice on hardware was to use a Tier-1 supplier, for the bankability and manufacturing throughput to meet deadlines. Lopez also flagged metering as a major obstacle at AES until the company set a standard for it.

POWER Magazine looked at a different shift: utilities moving from buying storage services to owning and operating batteries themselves. Under the older model, it noted, independent power producers built, owned and maintained many storage facilities and carried much of the responsibility for system integration, monitoring and life-cycle management. Ownership moves that burden in-house. POWER listed the requirements an owner must then define: data retention periods and data ownership models, how operational anomalies are detected, communicated and escalated, update testing protocols, deployment approval workflows and rollback procedures for vendor software, and integration with dispatch systems, marketing platforms and metering infrastructure. Without proper integration, it warned, utilities may lose opportunities to optimize storage revenue streams.

That service-versus-ownership distinction is the useful lens for a chain operator, and the comparison has limits. Those lessons come from utility-scale projects. GridPoint's storage is turnkey and added to a subscription that wraps equipment, installation and nationwide service into one monthly fee, which puts a chain closer to the service-buyer position POWER describes than to the owner-operator one. That suggests most of the integration work sits with GridPoint, though it is an inference from how the offer is structured. De Luca points to two decades of groundwork: the customer relationships, the building controls, the field infrastructure and years of revenue-grade energy data the company already has.

Still, the operator signing the contract keeps an interest in each item. POWER's point that storage often involves multiple vendors, integrators and service providers, and that unclear accountability opens gaps during failures, applies whoever owns the asset. The grid-scale experience turns those concerns into concrete questions:

• What first-year availability does the fee assume, and how are savings handled while a new site works through early equipment issues?
• Whose meter settles the bill savings and grid payments, and can the battery's operating data flow into the chain's existing energy reporting?
• How are battery software updates tested and rolled back, and who approves them?
• Who supplies the battery hardware, and does it meet the Tier-1 bar RWE's Zwingelberg recommends for bankability and delivery?
• How is grid program revenue shared, and does the monthly fee move if capacity prices fall?

The PJM capacity year as a deadline

De Luca pitches the money in practical terms. Facilities teams are always fighting for budget and often put off replacing equipment, risking failures in the process, he said, and deeper savings plus grid revenue can help them update their fleets sooner. That pitch only holds if the batteries are in the ground and dispatching when the expensive hours arrive.

The clearest test of the plan is timing. De Luca noted that PJM capacity prices cleared at the US$325 per megawatt-day cap for 2028/2029. Batteries installed at Chicago-area and New Jersey sites before that capacity year could be the ones positioned to cut that cost. The number to watch is how many of the first 100-to-500 kW systems are installed and running in PJM ahead of that window.