With an understanding of how the power market works and why large new loads change system costs, the next question is straightforward: what, exactly, are utilities forecasting for the next decade in Georgia, South Carolina, and North Carolina? The answer matters because these forecasts drive decisions about building power plants, expanding transmission, and setting future rates that customers will pay for many years.

Utilities forecast demand through formal planning documents known as Integrated Resource Plans (IRPs) or long-term resource plans. These filings project how much electricity customers will need, when they will need it, and what mix of generation and infrastructure is required to serve that demand reliably. While the details vary by state, the forecasts across all three states show one common theme: growth well above historical norms , driven by a combination of population growth, industrial development, electrification, and data centers.

In Georgia , demand growth is forecast to be dominated by data centers. Planning documents and regulatory discussions indicate that a very large share of projected new load over the next decade comes from hyperscale data centers locating across the state. Georgia’s electric system has historically grown steadily, but the current projections show a sharp acceleration tied to digital infrastructure. As a result, Georgia Power has proposed and received approval for a major expansion of generating capacity, including new gas-fired resources, batteries, and additional procurement authority. In Georgia’s case, data centers are not a secondary factor; they are the primary driver reshaping long-term demand forecasts.

South Carolina’s outlook is different in scale and composition. Growth projections are more moderate than Georgia’s, but still well above past trends. South Carolina utilities forecast demand increases driven by a mix of population growth, manufacturing expansion, and data centers. The planning emphasis has been on maintaining reliability as coal units retire and new load comes online. Dominion Energy South Carolina and Santee Cooper have focused on a combination of new natural-gas generation, solar additions, and battery storage, timed to coincide with expected load growth and unit retirements. In South Carolina, data centers are an important contributor, but they are part of a broader growth picture rather than the dominant force.

North Carolina’s forecasts reflect a more diversified demand profile. Utilities serving North Carolina project strong growth from population increases, electrification of transportation and heating, new manufacturing facilities, and data centers—particularly around urban and research hubs. Unlike Georgia, data centers are typically embedded within broader commercial and industrial growth categories rather than highlighted as a single dominant driver. Duke Energy , which serves large portions of North Carolina, has stated that expected load growth over the next 10 to 15 years is several times higher than what the region experienced in the prior decade, prompting the need for significant new generation and grid investments.

Across all three states, utilities face a similar planning challenge: forecasts must account not only for how much electricity will be needed on average, but for peak demand  during extreme weather and system stress. Data centers and electrification tend to raise both average and peak load, increasing the amount of firm capacity and reserve margin utilities must maintain. This requirement drives much of the proposed investment in gas-fired generation and storage, even in systems with growing amounts of solar power.

The risk embedded in these forecasts is timing and accuracy. If demand grows exactly as projected, the new infrastructure may be fully utilized and costs spread efficiently. If demand arrives more slowly—or if large projects are delayed or canceled—customers may still be paying for power plants and transmission lines that are underused. Conversely, if demand grows faster than forecast, reliability risks increase and emergency investments become necessary.

This is why demand forecasts sit at the center of today’s public debate. They are not abstract models; they are the assumptions that determine how much infrastructure gets built, how fast it gets built, and who ultimately pays. The next step is examining how those costs are allocated—and whether regulatory structures ensure that each class of customer pays its fair share of the system they depend on.