Dominion Energy Virginia C&I demand response and battery economics

Dominion Energy Virginia is vertically integrated, but it operates inside PJM, so a business in its territory has two ways to sell flexibility: to Dominion through its demand-side programs, or to PJM through a curtailment service provider. That is the key structural difference from Duke Energy Carolinas, where Duke’s own programs are the only buyer.

Every deep dive on this site has one feature that changes how its economics read. For Dominion C&I it is scale. Most business VPP programs we cover are built around office HVAC, cold storage or a 100 kW battery. In Dominion’s territory the customer class that matters most for flexibility is data centers, which can each draw hundreds of megawatts.

Dominion reports about 4 GW of data centers in Loudoun County, more than 20 GW of new data center load expected by 2031 and about 10 large-load requests a month (Dominion Energy). Where the transmission grid cannot yet serve them firmly, some customers accept non-firm service under its CAPFLEX pilot: 29 curtailment events and about 508 hours so far in 2026, the longest lasting about 194 hours. Dominion also counts 178 post-contingency local load relief warnings so far in 2026 (Dominion Energy).

Two lessons follow for smaller businesses. First, the value of flexibility in Northern Virginia is partly locational: a kilowatt reduced in a constrained load pocket is worth more than the same kilowatt elsewhere, and no current Dominion business program pays a locational premium. Second, data center backup generators are a large untapped resource, but Dominion’s VPP excludes fossil generation, so they stay in the separate Distributed Generation program.

Non-Residential Curtailment averages about $26,250 a year per participant (Dominion filing), which at $36 per kW implies sites of roughly 700 kW. Those sites could also sell through a PJM provider, where capacity at the cap is worth about $119 per kW-year before the provider’s share. Dominion’s program offers simpler terms and fewer events; PJM offers more money and more risk.

Stacking needs care, depending on M&V methodology. Dominion’s curtailment program and PJM demand response measure the same kilowatts, which is why they cannot be combined.

Schedule GS-2, for sites of 30–500 kW, bills demand on the highest 30-minute interval of the month: $4.963 per kW for distribution, $1.971 for transmission and $1.803 for generation in summer, $0.588 in winter (Schedule GS-2). That is about $95 per kW-year before riders. Energy is not time-of-use priced, so a battery earns little from shifting.

The site’s line above is only half of the deal. The developer pays the full $240k, carries maintenance, insurance and performance risk, and prices all of it into the contract to earn a return on its capital (Morgan Lewis). Third-party storage contracts usually run 15 years or more (Peak Power), and lenders treat 15- to 20-year terms as financeable (Illinois Power Agency). The chart below values each deal from the developer’s side.

With 25% of savings left to the site, a 15-year deal covers about 57% of the developer’s cost on our model, or about 65% if the battery earned 60% of PJM capacity value instead. At the modeled cost, a developer cannot earn 8% and still leave the site a share of bill savings. Battery-service offers are not priced the other way around, as a fee on top of handing over the savings: shared-savings providers promote a guaranteed share from day one (Gridwealth Electric), and Peak Power’s projects in Westchester, New York, split bill savings and market revenue with the building owner (NYSERDA case study). A deal that cannot fund a share is usually not offered at all. A guaranteed 15% share would need an installed cost about 75% lower, near $60k, well below today’s prices, so here a deal depends more on new program pay than on cheaper batteries; larger sites help, and providers such as Peak Power focus on facilities with more than 1 MW of load (Peak Power’s overview). The battery-service line above shows that 15% share. In Dominion territory today, a locational or capacity-linked payment is what would change that.

Compare: ComEd C&I for another PJM zone where capacity costs reach the customer through a peak load contribution, and Duke Energy Carolinas C&I for a vertically integrated utility without a market.