Why Duke Energy’s Powerpair Pilot Program Should Be Exp…
Contributed by Jake Duncan | Southeast Senior Regulatory Director, Vote Solar
Utilities are facing a perfect storm. Electricity demand is rising rapidly, driven largely by data centers. At the same time, bills are climbing, utilities are proposing billions of dollars in new infrastructure spending, and regulators are struggling to balance affordability with reliability. In Duke Energy’s case, the company is pursuing enormous capital expansion plans across the Carolinas while utility executives continue to receive staggering compensation.
The utility industry’s default response to these challenges has largely been the same: build more centralized infrastructure. More gas plants. More transmission. More substations. More rate base.
But utility infrastructure takes years to permit, finance, and construct. Large projects also shift enormous financial risk onto ratepayers, who ultimately pay for cost overruns, financing expenses, and utility profits through their bills.
In North Carolina, however, a quieter solution is already scaling. Thousands of households are installing solar paired with battery storage through Duke Energy’s PowerPair pilot program — and the results suggest utilities across the country should be paying attention.
What is the PowerPair Program?
PowerPair is a pilot program designed to encourage customers to install rooftop solar paired with battery storage. Customers can receive up to $9,000 in incentives for installing a new solar-plus-storage system. The program either encourages customers to shift load away from peak time under a time-of-use rate or requires participants to allow Duke to dispatch their battery through a virtual power plant (VPP) program.
The pilot was capped at 60 megawatts (MW) of solar capacity or three years, whichever came first. Yet after only two years, the program is already nearing full subscription.
According to Duke’s recently filed second-year program report, 6,297 customers have enrolled, resulting in 54 MW of rooftop solar installations and approximately 72 MW / 85 megawatt-hours (MWh) of battery storage capacity, assuming participants installed a single Tesla Powerwall 3 alongside their solar system.
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Small Pilot, Big Returns
To date, the program has spent approximately $48.6 million, including administrative costs. Yet the estimated total installed cost of the customer-owned solar and battery systems deployed through the program is roughly $227 million. In other words, the program leveraged an estimated $179 million in private capital investment.
That means every $1 of ratepayer-funded incentives unlocked approximately $3.70 in private customer investment.
This is fundamentally different from traditional utility infrastructure investment. Under the conventional model, ratepayers fund nearly the entire cost of utility-owned generation projects while utilities earn a regulated return on those investments for decades. Under PowerPair, customers voluntarily provide the majority of the upfront capital themselves because they benefit from the onsite generation and storage. Meanwhile, the grid benefits from reduced load and battery demand response, ultimately lowering energy bills for all customers—even for those without solar and storage.
The implications are significant.
Unutility-scale projects that require years of permitting, transmission upgrades, and large capital commitments from ratepayers, PowerPair rapidly deploys resources directly onto the grid edge using private investment. Thousands of distributed systems have been installed in only two years, providing new energy and capacity resources to the grid today — not a decade from now.
Favorable Ratepayer Economics
Because ratepayers fund only the incentive portion of the systems rather than the full installed cost, the effective cost to ratepayers of adding new resources through PowerPair is dramatically lower than that of traditional utility infrastructure.
Based on current program data and public average installation costs, PowerPair solar resources cost ratepayers approximately $360,976 per MW, while the battery resources cost approximately $403,402 per MW.
Comparing equivalent resource types reveals the scale of the difference. When comparing PowerPair solar to public estimates on Duke’s most recently approved combined cycle gas plant of $2,358,000 per MW — both energy-producing resources — PowerPair solar is roughly 80% cheaper per MW based on the costs of Duke Energy’s Anderson gas plant in South Carolina.
Similarly, when comparing PowerPair batteries to Duke’s public data on the most recently requested combustion turbine plant — both peaking resources designed to meet periods of highest demand — the proposed Smith combustion turbine plant is estimated to be $2,083,000 per MW, while the PowerPair batteries are approximately 85% cheaper per MW.
These are not small differences around the margins. They raise serious questions about whether utilities and regulators are fully accounting for the economic value of customer-sited distributed energy resources in long-term planning.
Effectively Using DERs in Utility Resource Planning
This question is currently being asked in Duke Energy’s ongoing Carbon Plan Integrated Resource Plan (CPIRP) proceeding in North Carolina.
Last year, Duke included an informational modeling sensitivity in which its model was allowed to select additional PowerPair battery demand response resources beyond the pilot program’s existing cap. Even within the limited scope of Duke’s analysis, the company’s model selected additional PowerPair resources in 12 of the next 15 years – an important finding that incentivizing demand side resources is a cost-effective grid resource.
However, Duke only evaluated expanded PowerPair deployment in a single scenario — and notably not in the scenario that ultimately became the company’s recommended portfolio.
Experts working on behalf of Vote Solar, the Southern Alliance for Clean Energy, and the Sierra Club later used Duke’s own PowerPair assumptions to analyze additional utility planning scenarios. In expert testimony in response to Duke’s CPIRP, Vote Solar explained that the scenario most reflective of current realities — one assuming approval of Duke’s proposed utility merger — selected nearly four times more PowerPair capacity than Duke’s original modeling.
None of this means utility-scale resources are no longer necessary— they are essential to maintaining a reliable electric system. Community-driven distributed energy resources alone cannot serve all load growth.
But that misses the point.
The point isn’t utility-scale versus distributed resources. The question is whether utilities are fully accounting for the value, economics, speed, and risk profile of customer-sited resources before defaulting to more expensive, utility-driven traditional infrastructure.
Programs PowerPair should no longer be viewed as niche customer offerings. They should be evaluated as a core infrastructure strategy.
About the Author
As Southeast Senior Regulatory Director at Vote Solar, Jake Duncan advances clean energy and energy justice in North and South Carolina through regulatory, legislative, and community engagement.
Prior to Vote Solar, Jake spent four years at the Institute for Market Transformation, where he furthered community-driven policy and regulatory efforts to equitably decarbonize the building sector. This included promoting the goals of local governments and community-based organizations in utility regulatory proceedings. Earlier in his career, Jake researched Integrated Resource Planning practices at Resources for the Future and interned at the Solar Energy Industry Association.
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