The United States has a deep pipeline of proposed renewable generation, battery storage, and large load projects ready to meet the country’s surging energy demand. And in many cases, investors are ready to fund them. So why are they stalling?
A major reason is transmission. Many of these projects cannot connect to the grid fast enough because the high-voltage transmission infrastructure needed to move power from where it’s generated to where it’s used hasn’t been built. So, while the technology and capital are there, closing the gap between producer and end user requires a legal and regulatory framework capable of moving infrastructure projects at speed.
What makes transmission law one of the central bottlenecks in the energy transition?
Building a major transmission line means navigating a complex web of overlapping corporate, municipal, and legal authorities, including:
- Regional planning. Deciding what to build and where requires coordination across utilities, grid operators, and state regulators, which don’t always share the same priorities.
- A state focused on keeping retail rates low, for example, may resist a line built mainly to help a neighboring state meet its clean-energy targets. Meanwhile, incumbent utilities may favor smaller local projects they own over larger regional lines open to competitive developers.
- Cost allocation. A line that crosses several states often benefits multiple states and multiple classes of customers. One of the hardest questions in energy law is deciding who pays for infrastructure whose benefits are widespread—and in what proportion.
- In practice, the fight is often over whether costs should be assigned narrowly to the generator or load that triggered the upgrade, spread broadly across regional customers, or allocated through a modeled “beneficiary pays” formula. That distinction can determine whether a project is attractive to financers.
- A transmission upgrade that improves reliability, relieves congestion, and unlocks new generation across a region may still fail if too much of the cost is assigned to a single developer, or if affected states cannot agree on how to allocate costs.
- State siting authority. States have long controlled where lines get built. A project that makes sense regionally can still stall if a single state along the route says no.
- For example, the proposed Northern Pass project would have carried Canadian hydropower into the New England market, but New Hampshire’s Site Evaluation Committee unanimously denied a siting certificate, the New Hampshire Supreme Court upheld the denial, and the developer promptly abandoned the project.
- Federalism. Layered on top of all this is the perennial tension between the federal goal to promote an interconnected grid and states’ traditional control over siting and retail rates. The Federal Energy Regulatory Commission (FERC) can require regions to plan new lines and allocate their costs, but it generally cannot force a state to approve a route, so a project with federal support can still be blocked at the state line.
These planning and permitting challenges show up most visibly in the interconnection queue. Before a new generation or storage project can connect to the grid, the transmission owner or grid operator must study its grid impacts and identify needed upgrades.
Interconnection reform
As of June, S&J Global reported the total volume of projects awaiting grid connection was 1,740 GW, exceeding the capacity of the existing US generating fleet. Public utilities and grid operators have struggled to keep up with interconnection requests because many queues were built for a smaller number of large, conventional power plants and for studying projects one at a time. That model broke down as developers submitted hundreds of smaller, often speculative requests, sometimes for the same project at different sites.
Projects that have reached commercial operation recently have typically taken about five years to move from interconnection request to operation, while most queued projects are ultimately withdrawn for various reasons before being built. Withdrawals can force restudies and change network-upgrade cost assignments for projects behind them, creating delay and cost uncertainty.
FERC Order No. 2023 seeks to address these issues by moving interconnection toward cluster studies, stricter readiness requirements, deposits, study deadlines, and penalties for transmission providers that miss them. Developers should still expect timing and cost uncertainty while the new processes take hold.
Regional transmission planning
FERC is also trying to move the system away from piecemeal, project-by-project decisions and toward long-term, regional transmission planning. FERC Order No. 1920, the most significant transmission planning and cost allocation rule in over a decade, requires grid operators to plan over a 20-year horizon and to build projects in structured processes for states to weigh in on how the costs of new regional lines get shared.
Although FERC Order No. 1920 is currently in effect and largely intact, and FERC has reaffirmed it on rehearing twice while expanding the role of state regulators, its future remains uncertain. The rule is under judicial review before the US Court of Appeals for the Fourth Circuit and has drawn forceful internal commission dissent over whether FERC exceeded its authority. The core themes driving the fight are the same ones that make transmission hard in the first place: how far out to plan, who pays, and how much say states retain over infrastructure that crosses their borders.
What this means for dealmakers, sponsors, and general counsel
For the people actually moving capital and projects, the practical implications are concrete:
- Interconnection risk is now a central diligence item. A project’s economics increasingly depend on whether and when it can connect, not just on its generation or storage profile.
- Cost-allocation exposure deserves early modeling. Who bears the cost of new transmission can materially change a project’s returns and should be stress-tested up front.
- Siting and permitting timelines drive deal timelines. State-level approval risk can be the difference between a project that closes and one that incurs the cost and legal exposure from missing project timeline milestones.
- Regulatory change is a variable, not a constant. FERC’s evolving framework, and the litigation around it, should be tracked as an active risk, not a fixed backdrop.
- Tax credit timing is tied to grid timing. There is no standalone federal tax credit for transmission, but the clean-energy credits that underpin many generation and storage projects depend on construction-start and placed-in-service deadlines. Interconnection and transmission delays can push a project past those deadlines, so credit eligibility should be modeled alongside interconnection and siting risk.
Transmission is the frontier
The energy transition is often framed as a race to deploy technology and capital. However, it’s increasingly a race to build the grid that connects them, and that race will be won or lost on legal grounds. Dealmakers should treat interconnection, cost allocation, and siting risk as front-line diligence issues and bear in mind the following:
- Transmission, not generation or financing, is now the binding constraint. For developers, that means testing grid access and transmission timing before committing to a site or technology. For investors and lenders, it means pricing interconnection and transmission risk into valuations and building it into milestones, conditions, and termination rights.
- The core disputes, regional planning, cost allocation, state siting, and federalism are fundamentally legal. Address these issues early. Bring regulatory and transactional counsel in at the site-selection and term-sheet stage and build transmission risk into early-stage agreements through interconnection and permitting milestones, allocation of network-upgrade costs, outside dates and extension rights, and termination or price-adjustment rights if transmission is delayed or costs shift.
- FERC is pushing toward long-term regional planning through Order No. 1920, but the reforms invite as many fights as they resolve, including a pending Fourth Circuit challenge. If the court largely upholds Order No. 1920, expect regions to move ahead with long-term planning and new cost-allocation methods, bringing more regional lines and more upgrade costs spread across customers. Position projects to benefit from planned lines and model those shared costs.
On the other hand, if the court vacates or narrows the order, expect planning to revert to shorter term, more fragmented processes and more state-by-state fights. Assume slower transmission build-out, rely less on future regional lines, and keep contract protections for delay and cost shifts in place.Developers should plan for both outcomes
Nixon Peabody is closely following transmission developments at the federal and state levels, including FERC’s generator-interconnection reforms under Order No. 2023, its regional transmission-planning and cost-allocation reforms under Orders No. 1920 and 1920-A, and related issues involving siting, permitting, rate incentives, and cost allocation. These developments underscore a broader shift: now, more than ever, transmission is a central legal, commercial, and regulatory factor in whether energy projects can be financed, built, and brought online.
