Electricity demand growth has returned to the United States planning conversation. EIA's January 2025 Short-Term Energy Outlook press materials described 2 percent demand growth in 2024 and similar growth expected in 2025 and 2026, the first three-year stretch since 2005 to 2007, with industrial and data-centre commercial loads leading. Transmission that was sized for a flat-load era will congest sooner. Order No. 1920 and its rehearing orders try to force long-term regional planning and clearer cost allocation. The gap between rule text and energised circuits remains the problem.
Where the gap shows up
Locational marginal prices diverge across constrained interfaces. Interconnection studies assign expensive network upgrades to clusters because the backbone was never built. Large loads receive deferral letters. Renewable plants curtail while gas units elsewhere run hard. Operators and EIA regional discussions have been pointing at this pattern as load forecasts rise.
Cost allocation still decides build-out
Order No. 1920's ex ante allocation mandate and the expanded state role under Orders No. 1920-A and 1920-B exist because late fights kill lines. States that want economic development from data centres must also face transmission cost responsibility. Free-ridership across RTO seams remains a national weakness that regional rules alone may not cure.
Retirements raise the stakes
EIA's February 2025 inventory planned 12.3 gigawatts of 2025 retirements, including 8.1 gigawatts of coal. Removing large steam units changes power flows. Retirements without transmission reinforcement can create new pockets of scarcity even when regional reserve margins look adequate on average.
Investment discipline
Not every proposed line deserves capital. Grid-enhancing technologies, reconductoring and better topology control should compete on cost and lead time. Lead times for transformers and conductor still argue for earlier decisions. Boards should demand scenario-based need statements consistent with Order No. 1920 factors, including laws affecting resource mix and demand, and should publish who pays.
Making the transition add up requires wires that match where electrons will be generated and consumed. Without them, interconnection reform and clean-energy statutes remain expensive queues.
The practical discipline is unchanged across fuel types and market constructs. Read the primary docket or statistical release before arguing about national destiny. Separate nameplate megawatts from accredited capacity, and contracted offtake from commissioned trains. Map interconnection and transmission lead times onto customer energisation promises rather than the other way round. Treat winter and summer extreme cases as design conditions. When federal policy shifts, update the slope of the forecast without rewriting physical laws. When state commissions push back on cost allocation, treat that push-back as part of the build path rather than as noise. United States energy infrastructure is financed, permitted and operated by people who must reconcile those constraints daily. Analysis that ignores them will not survive first contact with a peak day. Regional operators will continue to publish winter assessments, summer reliability outlooks and interconnection status reports. Those documents, read together with EIA inventories and FERC orders, give a clearer picture than any single speech. Investors should price execution risk honestly. Policymakers should resist the urge to treat one statute or one survey table as the whole system. The grid is a machine. Machines care about margins, not metaphors.