Duke Energy Carolinas C&I battery and demand response economics

Duke Energy Carolinas owns the generation, the grid and the customer relationship for businesses across the western Carolinas. There is no regional wholesale market, so demand response is valued against Duke’s own plant plans: in North Carolina, Duke projects that its proposed storage program would reach 26 MW within five years and avoid about 28 MW of new plants, saving about $13.6 million (Canary Media).

Every deep dive on this site has one feature that changes how its economics read. For Duke Energy Carolinas C&I it is the border between North and South Carolina. One utility, one control room and one fleet of plants, but two regulators, two sets of business rates and, for now, a battery program on only one side.

In South Carolina, PowerShare Storage (Rider SD) pays a one-time $120 per kW connectivity credit, $30 per kW more if the battery charges from renewables, a monthly capacity credit of $3.50 per kW less a loss factor, and 10¢ per kWh discharged in events. Duke may call 30–36 events a year of up to four hours, with up to four opt-outs, two of them in winter (Duke Energy). A battery in PowerShare Storage cannot also be enrolled in another Duke demand response program (Rider SD).

In North Carolina, the proposed Non-Residential Storage Demand Response program would pay a similar $120 per kW upfront and about $250 a month for a 100 kW battery, but the NCUC has not set a decision date (Canary Media). Unlike residential PowerPair, it would accept batteries added to existing solar (8MSolar).

The windows change what a battery is for. A three-hour window lets a 100 kW / 400 kWh battery run at full power, so in North Carolina its value would track the OPT-V demand price. South Carolina’s seven- and eight-hour windows spread the same energy thin, about 50 kW, which is why the program pay matters more there. On SC OPT, on-peak demand costs $18.87 per kW-month in summer and $13.16 in winter for the first 2,000 kW, and energy is 8.09¢ on peak and 4.04¢ off peak (SC e-tariff).

Before batteries, Duke’s business programs paid for curtailment. PowerShare pays large customers that can cut at least 100 kW, and its North Carolina capacity credit rose to $5 per kW in 2025 (Duke Energy). Power Manager for Business cycles rooftop HVAC at smaller sites for $30 per average kW of reduction (Duke Energy). Both are event-based demand response, valuable on winter mornings when Duke’s system peaks.

A battery in PowerShare Storage already discharges in Duke’s events, and on most event days those hours fall inside the OPT on-peak window, so the event discharge also lowers the bill. That overlap is intended rather than double counting, but Rider SD bars the same battery from PowerShare or other Duke programs. Stacking needs care, depending on M&V methodology.

On SC Schedule OPT, solar’s midday output in summer already falls in the 1–9 p.m. on-peak energy period, so storing it earns no energy spread: the “free” charge gives up an 8.09¢ kWh to avoid another 8.09¢ kWh later. The pairing pays through demand instead. Solar alone is not reliable enough to set the monthly on-peak demand, so we credit 100 kW of solar with only 10 kW. With the battery covering the evening part of the summer window and the early-morning part of the winter one, the combined shave rises from 50 kW to 80 kW.

Running together adds about $5k a year, plus a one-time $30 per kW renewable-charging adder from PowerShare Storage, $3,000 on 100 kW (Duke Energy). That is the multi-asset case at a Duke business: solar does not make the battery’s charge cheaper, but it shortens the hours the battery has to cover.

In South Carolina the battery pays back in about 15.6 yr on the bill alone and about 9.9 yr with PowerShare Storage. In North Carolina we cannot yet say: the program is a proposal and we could not verify the OPT-V demand prices, so the last capital stack row shows only what the filed program and the federal credit would cover.

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.

Even with PowerShare Storage, the South Carolina case falls short for a third-party owner. With 25% of savings left to the site, a 15-year deal covers about 76% of the developer’s cost on our model, up from about 62% on bill savings alone, and about 86% at a site that adds solar. 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 38% lower, near $149k, or a larger site where cost per kWh falls; 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. The long on-peak windows cap what a four-hour battery can shave, and there is no capacity market to add a second revenue stream.

Compare: SCE C&I for demand charges in a market state, Xcel Energy C&I and Puget Sound Energy C&I for other utilities without an organized market.