Why the Federal Energy Decision Slipping to End of June Reshapes Your Power Procurement Calendar
The deadline that has been driving boardroom planning for the past six months just moved by 60 days. The financial implications are the same. The pressure on your June calendar got worse.
By Keith Reynolds | Publisher & Editor, ChargedUp!
Federal regulators were supposed to issue a major decision on April 30 that would change how the largest electricity users connect to the grid and who pays for the upgrades that connection requires. That decision will not come on April 30. The Federal Energy Regulatory Commission has signaled it will act by the end of June 2026 instead, roughly 60 days later than the Department of Energy's original target. [1]
The slip matters for commercial real estate executives because of what the rule will say, not when. The proposed framework would shift the cost of upgrading transmission infrastructure to support new large electricity loads — anything above 20 megawatts, which means data centers, advanced manufacturing facilities, large industrial users, and the commercial properties that share their substations — onto the projects that triggered the upgrades. Today, those costs are typically socialized across all utility customers in the region. Under the proposed rule, they would be charged directly to the developer connecting the new load. [2]
That is a fundamental reset of how project economics get penciled. For an executive evaluating a site against an interconnection cost estimate from late 2024 or 2025, the assumption that the utility or the broader ratepayer base will absorb network upgrade costs is about to stop being true. Interconnection costs that once landed at $5 million on a 50-megawatt project could land at $40 million or higher under participant funding, with that delta flowing through directly to the developer's pro forma.
Why the Slip Makes the June Calendar Tighter, Not Looser
On the surface, a 60-day delay reads like breathing room. In practice, it compresses the decision window for owners working multiple deadlines simultaneously.
Three federal incentives that materially affect the financing math on behind-the-meter generation, EV charging, and energy efficiency upgrades all expire for construction starts after June 30, 2026. The Section 179D commercial buildings deduction at up to $5.94 per square foot — equal to $594,000 on a 100,000-square-foot building. The Section 30C alternative fuel vehicle refueling property credit at 30 percent of installation cost, up to $100,000 per location. Both sunset that day. The Section 48E investment tax credit for behind-the-meter solar and battery storage at 30 percent remains available beyond that date but with new domestic content restrictions tightening through 2027.
The FERC decision was expected to land April 30, giving owners roughly 60 days to react before the tax sunset. The new June timeline lands the federal decision and the tax sunset within the same compressed window, possibly within days of each other. That means executives evaluating projects now have less time, not more, to digest the federal cost-allocation framework before locking equipment, transformer commitments, and electrical contractor schedules to clear the June 30 deadline.
Compounding this, the North American Electric Reliability Corporation has signaled that it will not wait for the FERC order. NERC plans to issue what it calls a Level 3 Alert in early May addressing reliability standards for very large loads, the highest level the organization issues. That alert will inform utility positions in interconnection negotiations and rate proceedings beginning this summer, even before the FERC order is final. [3] Owners working data center contracts, large industrial site selections, or commercial development that depends on transmission-level capacity should expect their utility counterparts to harden their positions on cost allocation between now and the June order.
What Actually Changes in Your Portfolio Math
Three operational implications follow from the proposed framework.
First, jurisdictions and submarkets with capacity headroom on existing transmission infrastructure will get more valuable. Markets that require new transmission to serve large loads will get less valuable in relative terms, because the cost of those upgrades will land on the project rather than getting absorbed into general rates. For a developer evaluating a 100-megawatt site in a constrained market versus a 100-megawatt site in a market with substation headroom, the same building has materially different economics depending on which side of that line it sits on.
Second, the cost of the rate-base growth that utilities have been pursuing to serve hyperscaler load is now under closer federal scrutiny. The Center for American Progress utility rate case tracker counts 242 utilities pursuing rate increases that touch approximately 111.5 million customers. PECO has filed for $429 million. PPL settled for $275 million with a 10-year Data Center Tariff template that other utilities are watching closely. Xcel Colorado has filed for $356 million; Xcel Minnesota for $574 million across two years. [4] The proposed FERC framework is one piece of a broader regulatory pushback against the assumption that hyperscaler-driven costs should flow into general rates. For commercial owners absorbing utility expense, this is a positive in the medium term and a sharper short-term incentive to evaluate behind-the-meter alternatives.
Third, hybrid configurations — large loads paired with on-site generation or battery storage — get more attractive economically because the upgrade obligation gets sized against net rather than gross load. The exact rules for how regulators will study these projects remain to be decided in the June order. But the structural direction favors developments that can credibly demonstrate they will not draw their full nameplate capacity from the grid because they have on-site power.
The Decision in Front of You This Quarter
For executives running pro formas now, three concrete questions deserve a real answer before Memorial Day.
Has every project in the interconnection queue been confirmed against current cost-allocation rules? Projects that are already in queue with cost agreements signed before the FERC order are likely grandfathered under existing rules, but only if the studies and commitments are documented. Projects that are still in study or that signed letters of intent without firm cost numbers are exposed to whatever the June order sets as the new baseline.
Have transformer and electrical equipment commitments been locked? Wood Mackenzie continues to track a U.S. transformer shortfall of roughly 30 percent for power transformers and 10 percent for distribution units, with lead times for large power transformers at two to four years. [5] Power transformer prices are up more than 70 percent since 2019. Sites that haven't ordered transformers cannot meaningfully safe-harbor against the June 30 tax deadline, regardless of which way the FERC order lands. The window to lock equipment runs through May, not June.
Are the underwriting models still using socialized cost-allocation assumptions? Most pro formas built before the DOE directive in October 2025 assume that network upgrade costs flow through utility rate base. That assumption is increasingly inconsistent with where federal policy is going. Updating the cost-allocation assumption against participant funding gives an honest read on what the project will look like under the rules that will exist by mid-summer. [6]
The 60-day slip changes the calendar but not the financial direction. The cost of connecting large new loads to the grid is moving onto the projects that trigger the connections, the federal incentives that offset behind-the-meter alternatives expire on June 30, and the transformer market is operating with multi-year lead times. Owners working that math against a 2024 baseline are using the wrong numbers. The work between now and the June order is the work that will determine whether projects clear the new economics or get re-priced. [7]
References
[1] Snell & Wilmer: FERC Sets June Action on DOE's Large Load Interconnection Plan (April 17, 2026) — https://www.swlaw.com/publication/ferc-sets-june-action-on-does-large-load-interconnection-plan-putting-federal-state-boundaries-at-the-center-of-what-comes-next/
[2] FERC Docket RM26-4 landing page (Federal Energy Regulatory Commission) — https://www.ferc.gov/rm26-4
[3] NERC Accelerated Large Load Action Plan filing (March 2026) — https://www.nerc.com/globalassets/who-we-are/legal--regulatory/filings--orders/nerc-filings-to-ferc/2026/nerc_accelerated-ll-action-plan_rm26-4_signed.pdf
[4] Center for American Progress utility rate case tracker — https://www.americanprogress.org/article/utility-rate-cases-tracker/
[5] Power Magazine: Transformers in 2026 — shortage, scramble, or self-inflicted crisis? — https://www.powermag.com/transformers-in-2026-shortage-scramble-or-self-inflicted-crisis/
[6] IRS Section 179D Energy Efficient Commercial Buildings Deduction guidance — https://www.irs.gov/credits-deductions/businesses/energy-efficient-commercial-buildings-deduction
[7] Mayer Brown: FERC Large-Load Interconnection Preliminary Rulemaking — Key Takeaways — https://www.mayerbrown.com/en/insights/publications/2025/11/ferc-large-load-interconnection-preliminary-rulemaking-key-takeaways-for-data-center-developers-other-large-load-projects-and-investors
[8] CSIS: What's at Stake in FERC's Large Load Proposal (December 19, 2025) — https://www.csis.org/analysis/whats-stake-fercs-large-load-proposal
