There is a rare consensus in energy policy: the United States needs substantially more high-voltage transmission. Studies of deep load growth and clean-energy scenarios routinely find the country needs to roughly double or triple the pace of transmission expansion. Yet actual build rates have been flat or declining for a decade. The gap between “needed” and “built” is the transmission bottleneck — and it is not primarily an engineering problem. The wires are the easy part. Everything around the wires is hard.
Why transmission matters so much
Transmission does three jobs that nothing else can do at scale. First, it connects remote resources to load: the best wind is in the Great Plains, the best solar in the Southwest, and the load is on the coasts — hundreds of miles apart. Second, it provides geographic diversity: weather systems are regional, so a bigger grid can lean on neighbors when local resources falter; interregional transfer capacity is effectively shared insurance. Third, it relieves congestion: when lines into a load center are full, operators must run expensive local generation instead of cheap distant power, and consumers pay the difference.
The economics are large. Congestion costs — the premium consumers pay because cheap power cannot reach them — run into the billions of dollars annually across U.S. markets. Every major grid study finds that the benefits of a robust transmission expansion exceed the costs, often by multiples. The bottleneck is not that the math fails. It is that the math’s beneficiaries and the decision-makers are different parties.
The permitting maze
A major interstate transmission line typically requires approvals from every state it crosses, plus federal agencies for federal lands and water crossings, plus environmental review. Each state process is its own proceeding with its own intervenors, its own standard of review, and its own timeline — commonly 3 to 5 years per state, longer if litigated. A line crossing five states faces five sequential-or-parallel gauntlets, and a single state’s denial can kill the project.
This is the veto-point problem: the benefits of a regional line are diffuse (lower prices and better reliability across many states) while the costs are concentrated (landowners and communities along the route). Every jurisdiction along the path can say no; none can say yes for the whole. Federal backstop siting authority exists in limited form but has rarely been exercised successfully. The result is a system optimized for stopping lines, not building them.
Timelines tell the story: for illustration, a large interstate line can take 7 to 12 years from conception to energization, with the majority of that time consumed by permitting, routing, and litigation rather than construction. Construction itself — towers, conductors, substations — is typically 2 to 3 years. The industry’s joke is that it takes longer to permit a transmission line than to build the power plants it would connect.
Who pays: the cost allocation fight
Even when a line is permitted, someone must pay for it — and transmission’s regional benefits make cost allocation the most litigated question in the field. The governing principle, established by FERC Order 1000, is “beneficiary pays”: costs should be allocated roughly commensurate with benefits. In practice, quantifying benefits — avoided congestion, reliability value, access to cheaper generation, resilience — across states and decades is an analytical and political minefield.
The fight follows a predictable pattern. Exporting states (with cheap generation) resist paying for lines that mainly benefit importing states’ consumers; importing states resist paying for lines that mainly enrich distant generators. States with aggressive clean-energy goals want lines that import renewables; states without them see little reason to contribute. Every regional transmission plan is, underneath the engineering, a negotiated settlement of these conflicts — and the settlements frequently collapse, stranding years of planning work.
The planning problem: planning for whom?
Regional transmission planning under FERC Order 1000 was supposed to solve this by identifying the most efficient regional solutions. In practice, planning processes have tended to produce reliability-driven local upgrades — smaller projects justified by near-term reliability needs, allocated to local ratepayers — rather than large regional lines justified by economics or public policy. The reasons are structural: local projects have clear beneficiaries and simpler cost allocation; regional projects require multi-state consensus that the process cannot compel.
FERC has moved to strengthen planning requirements — mandating long-term regional planning over 20-year horizons, consideration of multiple future scenarios, and evaluation of a defined set of transmission benefits. But rules can require planners to identify beneficial lines; they cannot make states approve them or make beneficiaries agree to pay. Planning reform addresses the analysis. The veto points remain.
The interconnection tangle
Transmission scarcity shows up most visibly in the generator interconnection queue (covered in depth in the next article in this series): thousands of proposed generation and storage projects waiting years for studies that determine what grid upgrades they must fund. Many needed transmission upgrades are identified first in these serial studies, then allocated to individual generators — an inefficient way to build shared infrastructure, since each project pays for upgrades that benefit the whole system, and withdrawals cascade restudies through the queue.
What actually gets built
Given the obstacles, what does get built? Three categories dominate: local reliability upgrades (reconductoring, substation rebuilds, new transformers) approved through routine utility planning; merchant or contracted lines backed by specific customers (often large corporate buyers or public utilities) willing to underwrite the cost; and policy-driven lines where a state or group of states commits to cost allocation upfront. Notably absent: the large, multi-state, economically-optimal regional backbone lines that the studies say are needed most.
Order 1920: the long-term planning mandate
FERC’s major transmission planning rule (Order 1920) requires transmission providers to conduct long-term regional planning — looking out 20 years, across multiple plausible future scenarios, and evaluating a defined set of transmission benefits including avoided congestion, deferred generation investment, and resilience. The rule also requires states to agree in advance on a cost-allocation method for the resulting projects, addressing the beneficiary-pays fight before specific lines are proposed rather than after.
The rule’s significance is in what it forces planners to consider, not what it forces anyone to build. Identifying a beneficial regional line in a plan does not compel states to site it or beneficiaries to pay for it — those veto points sit outside FERC’s jurisdiction. Supporters argue that a rigorous, scenario-based plan with pre-negotiated cost allocation changes the politics: it is harder for a state to reject a line its own agreed-upon process identified as beneficial. Skeptics note that planning processes have produced elegant plans before, and the lines still did not get built. The rule is best understood as necessary but not sufficient — it fixes the analysis while the authority gap remains.
Merchant transmission and the anchor-tenant model
One workaround to the cost-allocation quagmire is to bypass it: merchant transmission lines are financed not through regional cost allocation but through contracts with specific customers. A group of utilities, corporate buyers, or a state procures capacity on the line through long-term agreements — the anchor-tenant model — providing the revenue certainty lenders require. The line’s costs fall on its contracted users, not on all regional ratepayers, which defuses the beneficiary-pays fight.
Several large interregional HVDC projects have advanced on this model, often backed by corporate clean-energy procurement or state clean-energy mandates. The limitation is scale: anchor-tenant lines serve their contracted customers well but are not planned as regional networks — they are point-to-point solutions that may bypass the meshed-grid benefits (shared reserves, geographic diversity) that make transmission most valuable. And the customers willing to underwrite billion-dollar lines are few. Merchant lines are a valuable complement to regional planning, not a replacement for it.
The workforce and supply-chain constraint
Even permitted, funded lines face a physical bottleneck: people and equipment. High-voltage transmission construction requires specialized lineworkers, and the workforce is aging — a large share of experienced transmission craftspeople are nearing retirement, with apprenticeship pipelines too small to replace them quickly. On the equipment side, large power transformers (the custom-built units at substations) have lead times stretching past two years, with a thin domestic manufacturing base and global competition for slots.
These constraints are less visible than permitting but equally binding: a line that clears every approval still cannot be built faster than transformers can be manufactured and crews mobilized. Workforce development programs, standardized transformer designs, and strategic equipment stockpiles are unglamorous but essential parts of any serious transmission expansion agenda. The industry’s joke about permitting timelines obscures a real risk — that after a decade of reform, the binding constraint becomes the supply chain.
The interregional question: how much sharing is enough?
A distinct debate sits atop the regional bottleneck: interregional transfer capability — the amount of power that can move between large regions (say, the Midwest and the Southeast, or Texas and its neighbors). Studies consistently find that modest increases in interregional transfer capacity deliver outsized reliability and economic benefits, because neighboring regions rarely peak at the same time and their weather risks are partially uncorrelated. During extreme events, the regions that fared best were often those that could import power from neighbors that were not simultaneously stressed.
Yet interregional lines face the worst version of every bottleneck: more states, more veto points, harder cost allocation (benefits accrue in emergencies that are hard to model and harder to assign), and limited planning coordination across seams. FERC has begun requiring transmission providers to consider interregional transfer needs in planning, but there is no institution whose job is to plan the continent-scale grid as a system. The result is a paradox visible in every major event review: everyone agrees more interregional capacity would have helped, and no one is clearly responsible for building it.
Paths through the bottleneck
Reform proposals cluster around the veto points. Federal siting authority — giving FERC or another federal body the power to override state denials for lines in designated national-interest corridors — would address the single-state veto directly. Standardized cost allocation with pre-negotiated formulas would reduce the beneficiary-pays litigation. Grid-enhancing technologies (the subject of our final article in this series) squeeze more capacity from existing corridors without new rights-of-way. And anchor-tenant models, where large load customers or states contract for capacity upfront, provide the revenue certainty that lets lines get financed.
None of these is quick. Transmission operates on decade timescales, and the bottleneck is ultimately a governance problem: the physical grid is regional and continental, but the authority to build it is fragmented across dozens of jurisdictions, each optimizing for its own constituents. Until the governance matches the physics, the wires will remain the hardest easy problem in energy.
It is worth stating the stakes plainly. Every year of delay in transmission expansion is a year in which cheap generation sits curtailed or unbuilt, congestion costs compound into consumer bills, and reliability margins thin against load growth that does not wait for permitting reform. The bottleneck does not just slow the energy transition — it taxes it, year after year, in billions of dollars of foregone savings and elevated risk. That is the cost of a governance structure built for a different century.