C&I DER Adoption Scorecard: Where Business Batteries Pay

This scorecard pulls together the commercial and industrial (C&I) cases from our utility deep dives. Each case asks the same question. If a developer owns a battery at a business site and shares savings with the host, does the deal earn its money back? The answer depends on four things, and the article takes them in order: what kind of program a territory runs, where the money tips, whether adoption follows, and what the grid gets in return.

Utility programs sit on a scale. At one end is event-based demand response: the utility sends a signal a few afternoons a year and pays for what the meter shows. In the middle is scheduled daily dispatch, where a battery discharges in the same window most summer days. At the far end is an orchestrated virtual power plant (VPP), where software forecasts, dispatches and verifies many devices for several grid services at once.

No territory reaches the orchestrated end yet. The furthest right are ComEd’s Scheduled Dispatch VPP, which runs every summer weekday from 4 to 6 p.m., Mass Save’s business Daily Dispatch, and Hawaiian Electric’s daily export window for home batteries. Residential and business programs often sit far apart in the same territory. Mass Save pays business batteries for daily dispatch but homes for 30 to 60 targeted events; Hawaii is the reverse.

Orchestration today happens mostly outside utility programs. In Texas, retail providers run home batteries in ERCOT’s pilot for aggregated distributed resources, as our Austin Energy deep dive explains, and hosted-battery companies such as Base Power own and dispatch the equipment themselves.

For each business case, we ran the same developer model used on every C&I deep dive. A developer buys the battery, claims the federal credit and depreciation, keeps program pay, and gives the site 25% of bill savings. The chart shows the present value of all that as a share of what the developer spends. At 100%, the deal earns an 8% after-tax return.

The four cases above the line share a profile. Eversource sites in Massachusetts and Connecticut combine demand charges near or above $20 per kW-month with program pay of $200 to $325 per kW-year on multi-year terms. SCE’s Option D gets there with no program pay at all, on a steep 4–9 p.m. price and high demand charges. Con Edison stacks the highest delivery demand charges we model with relief programs and a NYSERDA incentive.

Value per kW explains most of the ranking. Cases left of about $300 per kW-year can’t reach break-even without an upfront incentive, however the value is split. Incentives are the exception: ComEd’s $250 per kWh rebate lifts a case worth about $220 per kW-year to 96%, and NYSERDA’s upstate incentive does the same for NYSEG and National Grid New York.

A second way to read the same model is to ask what the battery would have to cost. The chart below finds the installed price at which a 15-year battery service still earns 8% while guaranteeing the site 15% of savings, the floor used on our deep dives.

6 cases work at $600 per kWh over 15 years, and 3 more (NYSEG, Hawaiian Electric (Oahu), PG&E) are within 25%. Most others need a price cut of 30% to 50%. Puget Sound Energy, APS, TOU M, Ameren Missouri, Portland General and Dominion Virginia need more than half off, which no near-term price path delivers. There, program design has to move first.

No single criterion decides the result. Strong demand-charge value appears in almost every case above the line, but Hawaii shows it is not enough alone: Oahu’s $32 demand charge reaches only 83% because Fast DR pays little and there is no upfront incentive. Ongoing capacity pay on a multi-year contract is the other common thread, and it matters to lenders as much as to returns.

Measurement method decides what stacks. Mass Save’s Daily Dispatch measures a battery by its own discharge, so the same battery can also cut the site’s demand charge. Site-baseline programs, such as Portland General’s Energy Partner, which uses the five highest of the last 10 typical days, count only load below that baseline, and a demand-shaving battery has already lowered it. Stacking needs care, depending on M&V methodology.

No home battery we model recovers its full cost in ten years from grid pay and bill savings. The closest cases, Hawaiian Electric at 82% and Eversource Connecticut at 80%, combine upfront or multi-year pay with a large rate spread or stored solar. California’s value comes almost entirely from the rate: storing solar for the 4–9 p.m. peak is worth about $1,000 to $1,340 a year under net billing. The household tipping point is backup value plus rate design. Program pay is only one part of it.

To test whether adoption follows the economics, we used the U.S. Energy Information Administration’s Form 861 data for 2025, released in October 2026. It reports customer-sited battery capacity by utility and customer class, both net-metered and not, and enrolled demand response. We divided battery megawatts by each utility’s 2025 summer peak.

The pattern is clear at the top. Eversource Massachusetts, SCE, PG&E, NYSEG and Con Edison lead on business batteries, and all five sit in the top half of our ranking. Ameren Missouri, Austin Energy and Consumers Energy sit near zero, and all three are below 75%. Across 16 utilities that report, the Spearman rank correlation is 0.66. The biggest exception is National Grid Massachusetts: the same Daily Dispatch pay puts it at 99% in our model, yet it reports almost no business batteries.

Reporting gaps are the weak point. EIA shows only 2.8 MW of business batteries at Eversource Connecticut. Yet the Connecticut Green Bank counts more than 140 MW of business projects approved in Energy Storage Solutions’ first four years. Many program batteries may not appear in utility filings, so treat low numbers as a floor.

Home batteries cluster where solar exports are worth little. Hawaiian Electric (152 MW per 1,000 MW of peak), PG&E and SCE lead by a wide margin, and all three credit exported solar well below the evening price. APS, with a falling export credit, is next. Massachusetts and New York pay more per kW for battery events, yet have a fraction of the adoption. For households, export rules move adoption more than VPP pay does.

The utilities with the most enrolled business demand response, Consumers Energy, National Grid NY and ComEd, are not the ones with the best battery economics; only ComEd is near the break-even line. Their megawatts come mostly from interruptible tariffs and curtailment by large industrial sites, programs that predate batteries. Enrolled demand response measures a utility’s history with curtailment. It doesn’t tell you whether batteries will follow.

A program can be a good deal for participants and a bad one for other ratepayers, or the reverse. The test is what the utility pays per kW-year against what that kW is worth to the grid. The clearest public benchmark is the wholesale capacity price in each market.

Three patterns stand out. New England pays far above the regional price: ISO-NE’s Forward Capacity Auction 18 cleared at $3.58 per kW-month for 2027/28, about $43 a year, against $200 to $325 from Mass Save and Energy Storage Solutions. Those programs are paying for transmission charges, local peaks and state policy goals that the capacity auction doesn’t price.

PJM runs the other way. Its 2027/2028 auction cleared at the $333.44 per MW-day cap, about $122 per kW-year, and the 2028/2029 auction again at its cap. Dominion’s business curtailment pays $36. ComEd businesses capture PJM capacity value through their own bills, which is why ComEd’s modeled program pay looks small. MISO programs sit near the market: Consumers Energy pays about $44 and Ameren Missouri up to $48, against MISO’s 2026/27 auction at about $46 annualized.

California and New York City pay the most for capacity, but through bills and local programs rather than battery pay. California’s 2025 system resource adequacy benchmark was $11.21 per kW-month (CPUC). New York City capacity hit a record $32.6 per kW-month in May 2026, according to Modo Energy.

The case for moving from event DR to orchestrated VPPs is strongest where program pay already sits below grid value, as in PJM, and where congestion is local and growing, as in New York City and around data center load. In those places, paying more per kW for daily, measured dispatch would still cost ratepayers less than the alternative, and it would move more territories past the tipping point.

The future of VPP to grow at scale will depend on multiple assets in unison at any given site: building controls, EV charging, batteries and solar, dispatched together and measured as one resource. A scorecard of single batteries understates what a multi-asset site can offer the grid, and what it could earn.

• Developers and investors: start with the break-even price chart; anything within 25% of today’s price is worth a site-specific model. Our finance and due diligence guides cover contract and policy risk.
• Regulators and utilities: compare your program pay with your market’s capacity price, then see where your territory sits on the spectrum. Our policy and regulation page tracks the market rules.
• Businesses: read your utility’s deep dive. Your own load shape and rate decide more than any territory average.