Dominion Energy delivers electricity to approximately 4.1 million customers across Virginia, North Carolina, and South Carolina. It owns about 30,700 megawatts of generating capacity, 10,800 miles of transmission lines, and 80,400 miles of distribution lines. Customers pay a monthly bill for the electricity they use, and state regulators set the rates Dominion is allowed to charge. That rate-setting process is the key to understanding the whole business, because it determines almost everything about how much money Dominion can earn. The company expects roughly 95% of its earnings to come from these state-regulated utility operations. The diagram below traces where the money goes.
Over the past five years, Dominion has been remaking itself. It sold its regulated natural gas distribution businesses to Enbridge in a series of transactions totaling about $9 billion in cash consideration, plus the assumption of related debt. It sold its 50% interest in the Cove Point natural gas facility to BHE for approximately $3.3 billion. The company is now focused almost entirely on electric utilities. Revenue has climbed from $11.4 billion in 2021 to $16.5 billion in 2025, which looks like growth. But the story underneath that number is more complicated.
The cash the business actually generates tells a different story from the revenue line. Operating cash flow has bounced between $3.7 billion and $6.6 billion over five years, which is typical for a big utility that has seasons and regulatory timing affecting when cash arrives. But free cash flow, which is what is left after the company pays for new equipment and construction, has gone deeply negative. It was already negative $1.2 billion in 2022, and by 2025 it had worsened to negative $5.0 billion. That means Dominion is spending far more on building new things than it is collecting from customers in any given year.
All that construction is being funded with debt. Net debt stood at $39.5 billion in 2021. It fell slightly as the gas asset sales brought in cash, reaching $37.0 billion in 2023. Then it climbed sharply. By 2025, net debt had risen to $46.3 billion, the highest level in the five-year window. The company has a $65 billion capital expenditure plan for 2026 through 2030, so debt is expected to keep rising as construction continues.
The biggest single project driving that spending is the Coastal Virginia Offshore Wind farm, known as the CVOW Commercial Project. It is a 2.6 gigawatt wind farm being built about 27 miles off Virginia's coast with 176 turbines. When complete, it is expected to power around 650,000 homes. The estimated total project cost is approximately $11.5 billion, excluding financing costs. Dominion sold a 50% stake in the project to Stonepeak in October 2024 for $2.6 billion, which helped share the financial load. The project has already encountered cost overruns, a government-ordered work stoppage in December 2025, and tariffs on imported equipment.
There are several specific risks worth understanding clearly. The first is the cost cap structure on the offshore wind project. Under an agreement with Virginia regulators, Dominion can recover all costs up to $10.3 billion. Between $10.3 billion and $11.3 billion, it can recover only half of the overrun. Between $11.3 billion and $13.7 billion, it recovers nothing. The current estimate of $11.5 billion puts the project right in the partial-recovery zone, meaning Dominion is already absorbing some losses that cannot be passed to customers.
The second major risk is regulatory. The Federal Energy Regulatory Commission, which oversees wholesale electricity markets, changed how it values power plant capacity in the PJM region in April 2024. PJM is the grid operator that covers Virginia and much of the mid-Atlantic. Changes to how capacity is valued can directly reduce Dominion's revenue from wholesale markets. Third, the offshore wind project relies heavily on foreign suppliers, with approximately 3.2 billion euros worth of contracts denominated in euros and Danish kroner. Tariffs on equipment from the European Union, Canada, and Mexico are already adding estimated costs of $0.6 billion to the project. The actual tariff impact will depend on rules that are still being decided.
One genuine source of demand growth is data centers. Data centers represented 28% of Virginia Power's electricity sales in 2025, up from 26% in 2024. The concentration of data centers in Loudoun County, Virginia is driving significant new investment in transmission and generation. PJM has projected 5.4% average peak annual load growth over the next ten years in Virginia Power's service territory. That is a meaningful tailwind for a regulated utility, because more demand means regulators are more likely to approve new construction and the rate increases that go with it. Starting in January 2027, Virginia Power will require 14-year contracts and demand minimums from large data center customers, which is designed to prevent those customers from leaving and leaving other ratepayers with stranded costs.