Think the recent surge in electric demand is a thing of the past? Think again.

Despite relatively flat demand since the early 2000s, advanced economies are experiencing a resurgence in electric demand. In the United States, domestic electric demand is projected to increase approximately 2 percent annually over the next three years—adding the total electric demand of California to the nation’s grid during this period.

This uptick—driven by increased data center activity, the electrification of the automotive and household appliance sectors, and a revival in domestic manufacturing, particularly among energy-intensive users like chip manufacturers—means that energizing large-load projects on expedited timelines will remain a challenge in the immediate future.

New Rules May Signal New Upfront Charges

The evolving energy landscape is prompting electric service providers to rethink how upgrade costs for new customers are covered. While utilities have a duty to serve, service now comes at a higher upfront cost for select users. Understanding cost variations across markets, industries, and among service providers is crucial; upfront contributions may otherwise impact a company’s business case in a particular location.

In some regions, capital- and energy-intensive investors have often avoided paying for transmission line upgrades and other system improvements required to service their projects, instead paying facilities charges for dedicated assets like substations. But expectations are shifting as utilities grapple with mounting interconnection requests, which in some instances represent cumulative loads that exceed their current peak demands.

For example, the Georgia Public Service Commission approved a new provision in January allowing Georgia Power, the state’s largest investor-owned utility, to modify standard terms and conditions for new customers with demands of 100 megawatts or more. This change aims to insulate existing residential, industrial, and commercial customers from risks associated with larger projects. Eligible costs for recovery include upstream generation, transmission, and distribution improvements required to service the new customers' facilities. Additionally, all contracts meeting this megawatt threshold must now be approved by the Public Service Commission.

Other jurisdictions are considering upfront payments for energy usage. The Public Utilities Commission of Ohio is expected to rule in the coming months on a new pricing scheme for data center users. Under the current proposal, a data center customer may be required to purchase up to 85 percent of its projected power demand in advance of consumption—regardless of actual electricity usage. Other specifics on how the potential provision would apply are yet to be determined. Regulators in other states, including California, Indiana, Texas, and Virginia, are also considering how to allocate upgrade costs required to serve data centers.

Electric utilities and their regulators seem most occupied by managing load growth spurred by data centers. But leaders contemplating any energy-intensive deployment should be prepared to actively engage with utilities to understand current practices and future expectations on cost recovery, including the level of support from regulatory bodies for economic development projects.

Staying Ahead of the Storm

Asking about the weather is no longer just small talk. Executives must now consider the immediate and long-term impacts of power supply interruptions on their operations, especially as extreme weather events become more frequent and the adequacy of reserve margins is tested. Energy-intensive operations are particularly susceptible when these weather events coincide with increased electric demand, often leading to supply disruptions.

Weather-related outages in the United States nearly doubled from 2014 to 2023 compared to 2000 to 2009. Severe weather—such as high winds and thunderstorms—and winter storms accounted for more than 80 percent of outages, with the South, Southeast, and Northeast experiencing the most impacts. The North American Electric Reliability Corporation (NERC) reports that maintaining reliability during winter is increasingly complex, raising questions about how utilities are incorporating resiliency and reliability measures into their system planning activities.

System reliability is challenged by more than just the weather. The pace of new resource additions and grid improvements is outstripped by asset retirements and growth in power demand. In December 2024, NERC released its long-term reliability assessment on 20 geographic regions across the United States and Canada, reporting that more than half of analyzed regions are at a “high” or “elevated risk” of electric supply shortfalls over the next five years. The Midcontinent Independent System Operator (MISO)—the electric grid operator for 15 states and one Canadian province—appears to be at the greatest risk, with supply shortfalls anticipated as early as this summer due to delayed resource additions and generation asset retirements.

• Behind-the-Meter (BTM) Solutions – Energy that can be generated or provided onsite and used directly by the end user. BTM energy systems do not require power from the grid to remain energized. Examples include onsite generation (such as solar), energy storage (such as commercial-scale batteries), and microgrids.
• Demand-Side Management (DSM) Solutions – Energy reduction and load management strategies that aim to increase operational efficiency and reduce energy costs, typically through shifts in the timing of energy usage. Many utilities offer demand response programs, which may provide financial incentives for achieving energy reduction targets at certain periods.

Corporate executives should rigorously evaluate electric service providers during the site selection process; doing so is critical for operational planning and risk mitigation. Multiple rounds of technical discussions and due diligence are required to adequately assess service providers' capabilities and potential blind spots—which could otherwise leave companies in the dark.

Spotlight: Fueling the Future with Shifts in Federal Energy Policy

Immediately following his inauguration in January 2025, President Donald Trump declared a national energy emergency, issuing an executive order directing federal agencies to develop “a reliable, diversified, and affordable [national] supply of energy.”

The National Energy Dominance Council is now tasked with delivering a set of recommendations to the president by late May on how the administration can expand domestic energy production, expedite permitting and regulatory requirements for energy projects, and lower energy costs. The council is also advising on incentives for private-sector energy production investments. Given the immediate directive to address supply constraints and emphasize baseload resources like fossil fuels, nuclear, geothermal, and hydropower, the scale, timing, and federal support of clean energy projects remain unclear.

At the same time, the National Governors Association is pushing for bipartisan support to accelerate infrastructure investments and permitting for the siting, approval, and construction of new energy assets, acknowledging tightening supply and the need for more firm capacity.

• How will changes in federal energy policy influence the availability, procurement, and cost of renewable energy?
• What are the financial implications of potential policy changes on operations?
• How will shifts in federal policy impact state-level regulations and influence utilities’ priorities, such as generation asset retirements?

The Takeaway

As power supply becomes more constrained in some regions, corporate executives planning facility deployments or expansions should explore behind-the-meter and demand-side management solutions to mitigate potential operational disruptions. Companies should also assess variations in upfront cost contributions across utilities and monitor pending regulatory changes affecting large-load users.