Transmission

Buildout, need, and constraints

How the US grid got built

The modern US grid is the product of two New Deal statutes and a 30-year postwar buildout. The Federal Power Act of 1935 gave the Federal Power Commission (now FERC) jurisdiction over interstate wholesale power and transmission, while the Public Utility Holding Company Act of the same year broke up the holding-company empires that owned most of the country's utilities. The Rural Electrification Act, signed May 20, 1936, then put $100 million of federal loans (about $1.9B in 2020 dollars) into rural distribution and transmission through cooperatives. About 10.9% of US farms had electricity in the early 1930s; by the early 1960s, the figure was 97%.

The technical foundation came earlier. Edison's Pearl Street Station opened in 1882 as a DC plant; Westinghouse and Tesla's AC system won the "war of currents" by the 1890s, which made long-distance transmission economic. Through the early 20th century, utilities operated as islanded systems. Interconnection accelerated after World War II, when electricity demand grew about 8% per year and the US added roughly 80,000 miles of new transmission between 1950 and 1963 alone. The grid passed 60,000 circuit miles by 1960 and kept building through the 1960s. The November 9, 1965 Northeast Blackout, which left about 30 million people without power, triggered the formation of the North American Electric Reliability Council in 1968 and the synchronous interconnection of the regional grids that exist today.

The buildout slowed in the 1970s. The National Environmental Policy Act took effect in 1970, the 1973 and 1979 oil shocks ended the era of falling real electricity prices, and a decade of steady demand growth gave way to slower, lumpier load increases. The 1992 Energy Policy Act opened wholesale transmission access; the 2005 Energy Policy Act added FERC backstop siting authority under Section 216, which the Fourth Circuit then narrowed in Piedmont Environmental Council v. FERC (2009). The Infrastructure Investment and Jobs Act of 2021 amended Section 216(b) to restore that authority; FERC implemented the amended statute in Order 1977 on May 13, 2024.

Quantifying the slowdown is awkward because record-keeping changed over the period. From 2010 to 2020, the US added about 33,000 circuit-miles of new or rebuilt transmission ≥100 kV (Niskanen Center). For the higher-voltage 345 kV+ class that Grid Strategies tracks, the 2010 to 2014 average was 1,700 miles per year, the 2015 to 2019 average was 925, and the 2020 to 2023 average had fallen to 350. The 2010s and 2020s have been the slowest decades for HV transmission additions since the modern interconnected grid was built.

The current pace, and what it would take

The US added 322 miles of 345 kV+ transmission in 2024 and 55 miles in 2023, per Grid Strategies' July 2025 "Fewer New Miles" report. 2024 was the third-slowest year for high-voltage construction in the past 15. The previous five-year period (2020 to 2023) averaged 350 miles a year, down from 925 in 2015 to 2019 and 1,700 in 2010 to 2014.

The DOE's 2024 National Transmission Planning Study estimates that the US needs to build about 5,000 miles per year of high-capacity intra-regional transmission to keep up with reliability and load growth, plus a separate buildout of interregional capacity. The 2023 Needs Study quantifies the longer-run target as 2.1x to 2.6x the 2020 system size by 2050 under current policies, up to 3.5x under deep decarbonization, with interregional capacity growing 1.9x to 3.5x over the same period. Princeton's Net-Zero America pathways give a wider range of 2x to 5x by 2050, depending on the assumed mix of clean firm generation and electrification.

More projects are in development than the completed-miles figures suggest. NERC's 2024 Long-Term Reliability Assessment counts 28,275 miles of >100 kV transmission in some stage of planning, permitting, or construction over the next 10 years, which NERC describes as a significant increase versus recent years. How many of those miles reach completion depends on the permitting, cost allocation, supply chain, and queue issues covered in the next section.

The Texas CREZ buildout shows what the pace can look like when a state preemptively approves a corridor. CREZ added 3,600 circuit-miles of 345 kV transmission between 2008 and 2014, at a cost of about $6.9 billion, to connect West Texas wind to the major Texas load centers. Wind curtailment in ERCOT fell from 17.1% in 2009 to 1.2% in 2013. CREZ also gets cited as a counterexample to multi-state coordination problems, because the project was contained within a single state regulator's authority.

Types of transmission

AC voltage classes

US transmission runs at standard AC voltages of 69, 115, 138, 161, 230, 345, 500, and 765 kV. The 765 kV class is the highest AC voltage in commercial US service, used mostly in AEP territory in the Eastern Interconnection. NERC defines the "bulk power system" as 100 kV and above, which is the threshold DOE and NERC use for total network mileage and pipeline figures. Grid Strategies tracks new construction at 345 kV+, which is why the 2024 number on this page is 322 miles rather than a larger figure that would include lower-voltage replacements.

HVDC and converter technology

HVDC moves bulk power over long distances at lower losses than AC and provides an asynchronous link between AC systems (for example, between the Eastern, Western, and ERCOT interconnections). US HVDC projects under construction or recently operational run at ±400 kV (Champlain Hudson Power Express), ±525 kV (SunZia, TransWest Express), and ±600 kV (Grain Belt Express). China operates ±800 kV and ±1,100 kV UHVDC lines at commercial scale; the US has no operational lines at those voltages.

Converter technology divides into two families. Line-commutated converters (LCC) use thyristors and are the older bulk-transfer design; voltage-source converters (VSC) use IGBTs and add capabilities that LCC cannot match, including embedded HVDC, multi-terminal designs, black-start, and reactive-power control. Most new US HVDC (SunZia, CHPE, Grain Belt Express) is VSC. HVDC overhead lines are typically economic for transfers above roughly 500 miles, and HVDC submarine or underground cables for spans above roughly 50 miles.

Overhead, underground, and submarine

The US transmission network is overwhelmingly overhead. Underground HVAC at transmission voltages typically costs 5 to 10 times overhead per mile, with wide project-specific variation, so it gets used mainly in dense urban areas where the right-of-way is unavailable. The Champlain Hudson Power Express, a 339-mile ±400 kV HVDC line running underground and underwater from the Quebec border to Astoria, Queens, is the leading current US example of long-distance underground or submarine HVDC. CHPE was about 99% trenched as of September 2025 and is targeted for commercial operation in May 2026.

Interregional transfer and macrogrid concepts

NREL's Interconnections Seam Study (2020) modeled HVDC ties between the Eastern, Western, and ERCOT interconnections and reported benefit-to-cost ratios of 1.3 to 2.5 across scenarios. MISO's Long-Range Transmission Planning approved a $10.3B Tranche 1 portfolio in 2022 (benefit-to-cost ratio 2.6 to 3.8) and a $21.8B Tranche 2.1 portfolio in 2024 that includes a 765 kV backbone. The MISO-SPP Joint Targeted Interconnection Queue (JTIQ) is a coordinated interregional set approved in 2024. DOE's 2024 National Transmission Planning Study published the most recent federal map of high-opportunity interregional interfaces.

Grid-enhancing technologies

Grid-enhancing technologies (GETs) and reconductoring add capacity to the existing network without building new lines. See the dedicated section below for the four GETs categories and the GridLab HTLS reconductoring findings.

Why so little gets built

Permitting

Federal NEPA review for transmission projects that trigger an Environmental Impact Statement averaged 4.3 years across 37 projects reviewed from 2010 to 2020, with a range of 1 to 11 years, per the Niskanen Center's inventory. State siting is usually the binding constraint. Each state runs its own siting process, and multi-state projects (Grain Belt Express, the New England Clean Energy Connect, Mountain Valley Pipeline's electric analog) face sequential or parallel proceedings in every state they cross.

FERC backstop siting authority under FPA Section 216 was effectively limited by Piedmont Environmental Council v. FERC, 558 F.3d 304 (4th Cir. 2009), which held that FERC's backstop did not apply when a state actually denied an application (only when a state "withheld approval" for more than a year). The Infrastructure Investment and Jobs Act of 2021 amended Section 216(b) to restore the backstop. FERC implemented the amended statute in Order 1977 on May 13, 2024, and added Tribal-lands provisions in Order 1977-A on October 17, 2024. State denial is now a trigger for FERC review, though the procedural mechanics have not yet been tested in a contested filing.

Cost allocation

Cost allocation is the second permitting question: who pays for a line once it is approved. FERC Order 1920 (May 13, 2024) requires public utilities to do 20-year long-term regional transmission planning and to adopt one or more long-term regional cost-allocation methods. States are consulted but do not have a veto. Order 1920-A (November 21, 2024) added state involvement provisions on rehearing. MISO uses postage-stamp energy-withdrawal cost allocation across its Midwest sub-region for the LRTP tranches; SPP uses a "highway/byway" method that spreads higher-voltage costs more broadly. Disputes over cost allocation are a common reason multi-state interregional projects stall, because benefits accrue across state borders while costs are assigned to specific ratepayers.

Eminent domain and landowner opposition

Eminent domain authority for transmission varies by state. Most states require a Certificate of Public Convenience and Necessity (CPCN) before eminent domain can be used; some (Missouri, Iowa) require the developer to hold a utility franchise in the state. Grain Belt Express and similar merchant transmission projects have spent years in state-level access cases for this reason. Landowner opposition along the route is a recurring source of delay even where eminent domain is theoretically available.

Supply chain

Large power transformer lead times in Q2 2025 ran about 128 weeks (~2.5 years) for power transformers and 144 weeks for generator step-up units, up from roughly 50 weeks pre-2022. The largest units now quote up to 210 weeks (~4 years), per pv magazine USA's May 11, 2026 reporting. Prices are 4 to 6 times pre-2022 levels. The US has one domestic producer of grain-oriented electrical steel, the core raw material for transformer cores: Cleveland-Cliffs' Butler, Pennsylvania mill (the former AK Steel plant). HVDC converter station supply (Hitachi Energy, Siemens Energy, GE Vernova, NR Electric, China Energy Engineering) is similarly capacity-constrained.

Interconnection queue backlog

Active interconnection queues hold about 2,290 GW of generation and storage at end of 2024, per LBNL's Queued Up 2025 Edition (1,400 GW generation plus 890 GW storage; queue total fell from the 2,598 GW year-end 2023 peak as withdrawal rates outpaced new requests). Median time from interconnection request to commercial operation is now over 4 years for projects built 2018 to 2024, against under 2 years for 2000 to 2007 projects. Queue backlog and transmission backlog are linked: most queue withdrawals trace to inadequate transmission, network-upgrade cost assignments, or interconnection-study delays. For more on the queue itself, see Blizzard Power's interconnection queue focus topic.

Grid-enhancing technologies and reconductoring

Reconductoring replaces conventional ACSR conductors with high-temperature low-sag (HTLS) conductors that have composite or carbon-fiber cores. The new conductors carry more current at higher operating temperatures without sagging into NESC clearance violations, which lets a utility roughly double the line's thermal capacity using the existing towers and right-of-way. GridLab's 2024 reconductoring technical report finds that reconductoring can deliver about 2x current capacity on most existing rights-of-way, on much faster timelines than greenfield builds. A documented Nevada upgrade increased one line's ampacity from ~300 A to ~1,000 A after reconductoring, per the same GridLab report.

Three other GETs categories sit alongside reconductoring. Dynamic line rating uses real-time weather data to add 10 to 30% capacity in many conditions, particularly under cool or windy weather. Advanced power flow control devices redirect flows across the existing network to relieve congestion. Topology optimization software reconfigures the grid in near real time to route around bottlenecks. FERC Order 1920 now requires transmission providers to consider GETs in long-term regional planning, and the DOE's $1.9B SPARK funding opportunity (Speed to Power through Accelerated Reconductoring and other Key Advanced Transmission Technology Upgrades, announced March 2026) is the primary federal funding source for deployment.

Wildfires and the transmission-line question

Two of the most destructive US utility-caused wildfires of the past decade were transmission events. The November 2018 Camp Fire (85 deaths, about $16.5B in damages, the town of Paradise destroyed) was ignited by a worn C-hook on PG&E's 115 kV Caribou-Palermo transmission line, per CAL FIRE's May 15, 2019 finding and the CPUC SED investigation that followed. The January 2025 Eaton Fire in Altadena, which destroyed more than 9,000 structures, is likely tied to re-energization of a decommissioned SCE line in the Mesa-Sylmar 220 kV corridor. Edison CEO Pedro Pizarro publicly described SCE equipment as the "likely" cause in December 2025; the Department of Justice sued SCE in September 2025 alleging the company's equipment caused the fire. The official CAL FIRE report is pending as of May 2026.

Aggregate ignition counts are dominated by distribution. In the first half of 2024, PG&E reported about 30 CPUC-reportable ignitions from distribution infrastructure in high fire threat districts and about 2 from transmission, per the figures referenced in the CPUC's September 2024 mid-year safety report. That split is one utility's CPUC-reportable data for California HFTDs, not a nationwide statistic. The structural reasons typically cited for the split: distribution lines outnumber transmission by roughly 25 to 1 in total mileage, run at lower clearances, sit inside smaller rights-of-way with more tree contact, and see more frequent low-energy faults. Transmission lines have wider rights-of-way, regular vegetation management, and more inspections. Recent large California fires have come from both line types (Camp and Eaton from transmission; Dixie 2021 and others from distribution), and the largest by ignition count are distribution.

Transmission ignitions are rare relative to distribution but high in damages when they occur. The Camp Fire and the Eaton Fire are the two recent reference cases cited in current wildfire policy and utility liability discussions.

Further reading