Utility spending is increasingly governed by regulatory approval schedules, making state commissions, not corporate boards, the practical gatekeepers of many electrification timelines. S&P Global forecasts electric and gas utility capital expenditure in the RRA Financial Focus group will reach roughly $153 billion by 2028, up from an estimated $139.6 billion in 2026 and $110.9 billion in 2025. Southern Company alone now expects to spend more than $51 billion between 2026 and 2028, a 34% increase over its own forecast from just seven months earlier. American Electric Power has budgeted $77.9 billion for 2026 through 2030. None of that money moves instantly into service. It moves through a rate case process that determines whether, and when, the utility gets paid back for building it.
The Rate Case Clock Utilities Actually Run On
DTE Electric filed a rate case with Michigan regulators on April 28, 2026, requesting a $474 million base rate increase tied to a projected twelve-month period ending February 2028. A final order from the Michigan Public Service Commission is not expected until February 2027, roughly ten months after filing, and the rates it sets will not take effect until later still. That gap between spending capital and recovering it through approved rates is what utility regulation calls regulatory lag, and it routinely runs 12 to 24 months on a single rate case. A utility that spends ahead of an approved rate case earns no return on that investment until the commission acts, which gives utilities every financial incentive to sequence spending around their own recovery timeline rather than a customer's public commitment date.
That incentive is not new. What has changed is the volume of electrification-driven load now competing for a place in that sequence, and the specificity with which companies have started publishing the dates their own plans depend on.
Disclosure Rules Turned a Planning Gap Into a Legal One
The Science Based Targets initiative (SBTi) released version 2.0 of its Corporate Net-Zero Standard on June 11, and companies will transition to it over time as their targets are updated or revalidated under the revised standard. California's SB 253 requires companies meeting the revenue threshold to begin reporting greenhouse gas emissions under regulations adopted by the California Air Resources Board (CARB), with Scope 1 and Scope 2 reporting beginning under the program's implementation schedule. Frameworks from the ISSB and the UK's Sustainability Reporting Standards go further: IFRS S2 and the UK standard both require companies to disclose climate-related targets where they exist and explain progress toward them, though neither requires a company to set one. A target that depends on a specific interconnection or transmission upgrade landing on schedule is no longer a private planning assumption. It is a disclosed commitment sitting next to audited financial statements, and the gap between what companies pledged and what infrastructure can support is already showing up in the numbers. Accenture estimates only about 16% of the world's 2,000 largest companies by revenue are currently on a trajectory consistent with reaching net zero by 2050.
Finance and sustainability teams that set those targets between 2020 and 2022 were working from assumptions about grid capacity and interconnection speed that have not held up, a pattern already reshaping how boards think about energization timelines more broadly. The rate case clock adds a second, more specific layer to that gap. A company's electrification plan might be technically sound and fully funded, and still depend on a piece of utility infrastructure that has not yet cleared its own regulatory process, with no guarantee the two timelines will land in the same fiscal year.
What This Means for the Capital Planning Cycle
The practical fix is not waiting for the utility to catch up. It is building a habit of checking, at the point a target date gets set, whether the specific interconnection, substation upgrade, or transmission project it depends on has an open docket and where that docket sits in its commission's queue. That single data point, publicly available in most states through commission dockets and utility integrated resource plans, tells a finance team more about whether a 2028 target is achievable than any internal engineering estimate can. It is the same discipline already being applied to permitting and water risk in site selection, extended to the utility side of the ledger. Boards that treat a target date as a communications decision, rather than a regulatory one, are the ones most likely to be explaining a miss instead of managing one.
