Duke Energy sells electricity and natural gas to homes and businesses across six states: North Carolina, South Carolina, Florida, Ohio, Indiana, and Kentucky. In almost every one of those states, Duke is the only electricity provider allowed to operate, so customers cannot switch to a competitor. The company charges rates that state regulators approve, and those rates are set to cover costs plus a reasonable profit. With roughly 8.7 million electric customers and 1.8 million gas customers, this is a business built on recurring, essential payments that arrive whether the economy is booming or struggling. The diagram below traces where the money goes.
Revenue has climbed steadily from $24.6 billion in 2021 to $32.2 billion in 2025. That is consistent, predictable growth of about $1.9 billion per year on average. Gross margin, which measures how much of each dollar of revenue is left after direct costs, recovered from a low of 47.8% in 2022 back to 59.6% in 2025, close to where it was at the start of the five-year stretch. The 2022 dip coincided with a sharp rise in fuel costs that squeezed the gap between what Duke paid to generate power and what it collected from customers. The recovery since then reflects both higher approved rates and lower fuel cost pressure.
Operating cash flow tells a similarly improving story. It was $8.3 billion in 2021, dropped to $5.9 billion in 2022, then climbed to $12.3 billion in both 2024 and 2025. The company is generating more cash from its core operations than at any point in this five-year window. The problem is where that cash goes. Duke is in the middle of a massive building program, planning to spend between $200 billion and $220 billion over the next decade on new power plants, grid upgrades, and infrastructure. Capital spending consistently exceeds operating cash flow, which means free cash flow has been negative in four of the last five years.
That building program has to be paid for somehow, and the answer is debt. Net debt rose from $66.8 billion in 2021 to $89.6 billion in 2025, an increase of nearly $23 billion in four years. To raise additional funds without piling on more debt, Duke agreed in August 2025 to sell a 19.7% stake in its Florida operations to Brookfield for $6 billion. It also agreed to sell its Tennessee gas business to Spire Inc. for $2.48 billion. Both deals are still subject to regulatory approvals. These transactions provide cash today in exchange for giving up a slice of future earnings from those operations.
The reason Duke is spending so heavily is that demand for electricity in its service areas is growing faster than it has in decades. Data centers, artificial intelligence infrastructure, and manufacturing plants moving into the Carolinas, Florida, and the Midwest are all drawing more power. Duke won 87 economic development projects in 2025 alone, representing over $30 billion in new capital investment and roughly 29,000 new jobs inside its service territories. That demand growth is the core argument for all the spending. If the new load actually arrives, the new plants and grid upgrades will be used heavily, and regulators are likely to approve higher rates to pay for them.
Regulators have generally been cooperative. In North Carolina, Duke secured a $768 million revenue increase from Duke Energy Carolinas in 2024 and a $494 million increase from Duke Energy Progress in 2023. Duke Energy Florida got a $262 million rate increase effective January 2025. Duke Energy Indiana got a $385 million increase effective March 2025. The pattern shows state commissions approving higher rates as Duke makes larger infrastructure investments, which is the engine that converts capital spending into future earnings.
Several serious risks sit alongside this picture. The biggest is coal ash. Duke stores large amounts of coal combustion residue in landfills and ponds across its service territory. New federal rules issued in April 2024 expanded cleanup requirements to sites that were previously unregulated. The costs could substantially exceed current estimates, and there is no guarantee that regulators will allow Duke to pass all of those costs to customers. Duke is also legally challenging those rules, so the final outcome is uncertain.
Nuclear is a second major risk area. Duke operates 11 nuclear reactors at six stations. Those reactors produce about 27.5% of the electricity Duke generates, and they do so at a fuel cost of just 0.58 cents per kilowatt-hour, far cheaper than natural gas at 3.95 cents or coal at 4.19 cents. Keeping those reactors running requires relicensing approvals from the Nuclear Regulatory Commission. One reactor, Robinson, has a license expiring in 2030, and Duke filed for an extension in April 2025. If any relicensing effort fails, Duke loses a cheap, carbon-free power source and must replace it with something more expensive. The spent nuclear fuel that accumulates at these plants also has nowhere permanent to go, since the federal government has not built a storage facility, leaving Duke to manage it on-site indefinitely.
Federal tax credits add a third layer of uncertainty. Duke relies on nuclear production tax credits provided under the Inflation Reduction Act to help keep electricity costs manageable for customers while funding its clean energy commitments. If Congress changes or eliminates those credits, the economics of running the nuclear fleet shift, and the promised customer savings evaporate. Duke's 2025 filing notes this risk explicitly and describes active lobbying to preserve the credits.
There is also the memory of Christmas Eve 2022, when Duke cut power to customers during a winter storm for the first time in its history. Broken equipment and software failures both played a role. Federal regulators investigated. The incident is a reminder that a company spending hundreds of billions on new infrastructure still has to keep the existing system running reliably every single day.