U.S. utilities are heading into the largest capital spending cycle in decades, and state regulators are making them prove each dollar belongs there before it reaches a customer’s bill. S&P Global Market Intelligence tracks the coming five years of grid investment across dozens of major utilities, and the number keeps climbing. Rising electricity demand, aging equipment and the push for greater reliability are colliding with sharper scrutiny in state rate cases over a familiar question. Which investments have actually been justified well enough for customers to pay for them.
Regulators are still approving substantial rate increases, so this is not a story about utilities losing ground wholesale. A Lawrence Berkeley National Laboratory review found that commissions approved, on average, 64% of the revenue increase dollar amounts utilities requested between 2021 and 2025. That figure does not measure how many individual capital projects survived review. It explains why a reduced rate request should be read as negotiation, not a halt to grid investment. The real fight is over evidence, the forecast that makes a project necessary, its cost, its timing and which customers actually benefit.
S&P Global Tracks Nearly $1.3 Trillion in Planned Spending Through 2030
Investment plans have grown fast. S&P Global’s Regulatory Research Associates group now forecasts $1.295 trillion in aggregate capital spending across 46 tracked utilities for 2026 through 2030, up from a $1.169 trillion forecast the firm published just months earlier. Data center growth is the single biggest driver, with S&P Global Energy CERA projecting more than 45 gigawatts of new peak load and 374 terawatt-hours of added demand through 2035. That pace of spending is exactly what is drawing regulators into closer review of individual projects, on top of the usual question of whether utilities need grid investment at all.
A Rejected First Plan Forced Ameren to Rework Its Illinois Grid Case
The Illinois Commerce Commission rejected Ameren Illinois’ initial four-year grid plan, sending the utility back to revise its proposal after months of stakeholder workshops. When the commission approved the resubmitted plan in December 2024, it also cut Ameren’s requested rate increase by roughly 7%, to $309 million, while still authorizing the underlying grid work the company needed to keep the system reliable. The process kept investment moving. It just subjected each piece of that investment to closer questions about affordability and effectiveness first.
Michigan Approved Less Than Half of What DTE Requested
An individual rate case shows the same pattern. Michigan’s Public Service Commission approved a $217.4 million annual revenue increase for DTE Electric in January 2025, 52% below the $456.4 million the utility had originally requested. Commissioners still backed spending on legacy equipment upgrades, tree trimming and other reliability work central to DTE’s case. The cut landed on the size of the request. The underlying capital program came through largely intact, a split that matters more than the headline number suggests.
Data Center Forecasts Are Becoming a Capital Planning Test
Large prospective loads add a harder layer of uncertainty to these cases. A data center or industrial project can require a new substation or line upgrade well before it ever draws power, and utilities have historically built ahead of firm commitments to avoid delaying service. If a project changes scale or never materializes, regulators and customers are left arguing over who absorbs the cost of infrastructure built around a forecast that missed. More than 23 states have already adopted large-load tariffs requiring deposits and minimum contract terms specifically to guard against that risk, and Georgia regulators are separately investigating whether an existing rate structure shifts power costs onto the wrong customer class entirely.
That makes the quality of a utility’s demand assumptions consequential in a way it rarely was a decade ago. Commissioners can now ask whether prospective customers have signed firm load contracts, when that demand is actually expected to arrive, and how costs get reassigned if the real number comes in lower. A large interconnection inquiry on its own does not prove the full requested load will ever get built.
What Energy Buyers Should Track in a Rate Case
For facilities teams, the stakes go beyond future rates. If a utility has to revise a project, supply more evidence or change how it allocates cost, the timing and terms of a new service connection can shift too. A facility expansion that depends on added electric capacity needs a schedule grounded in the utility’s approved work and its actual pace of delivery, not the long-range spending forecast alone.
A proposed capital budget is an early signal, not a locked-in price. Energy and facilities managers get a clearer picture by tracking three things as a case moves through review, which projects actually survive, when approved costs are scheduled to hit rates, and whether a proposed tariff assigns specific costs to new or unusually large loads rather than spreading them across everyone. Reliability claims deserve the same scrutiny. When a utility ties spending to fewer outages or faster restoration, the promised service improvement matters as much as the dollar total, and it can shape decisions about backup power, demand flexibility and the timing of a facility’s own upgrades.
The question regulators are asking has gotten specific. What does this investment deliver, when is it needed, and who pays for it. For large electricity customers planning their own capital projects, the answer increasingly determines both what it costs to keep an existing facility running and how fast the next one can get connected.