State Permitting Challenges: Electric Transmission
Transmission is the connective tissue between power plants and consumers. New transmission has become more expensive while the need for expansion increases from changes in generation and load growth. Unlike generation, which requires a single site in one state, transmission is linear and often spans multiple states. This makes transmission uniquely vulnerable to inefficiencies in state permitting, which prevent, delay, and/or increase the cost of expansion.
Transmission is one of the most highly regulated forms of economic activity. Under the purview of prescriptive regulation, most transmission is centrally planned by utilities or regional planners. The costs are recovered through mandatory charges on customer bills. After planning and cost-recovery processes, projects seek permitting and siting approval from relevant federal, state, local, tribal, and private authorities.
The Federal Energy Regulatory Commission (FERC) has authority over interstate transmission planning and cost allocation rules. FERC holds limited backstop authority to approve transmission projects within “national interest” corridors only. This contrasts with most other forms of interstate infrastructure, where Congress provided exclusive and preemptive federal permitting and siting authority. Instead, states generally have primary jurisdiction over intrastate and interstate transmission siting and applicable permitting, plus a pronounced role for local authorities. This makes transmission permitting piecemeal and haphazard.
States Role
States vary in approval authorities and processes. Thirty-three states assign primary responsibility to state public utility commissions (PUCs), eight use special decision entities (i.e., siting boards), and four use a non-utility commission agency. Most remaining states leave authority to applicable local governments like county zoning boards. Despite structural variances, the criteria for approval are relatively consistent and include:
- A demonstrated need through analysis of the transmission system;
- The comparison of project benefits to costs; and
- Land use and environmental effects, such as scenic, agricultural, recreational, ecological, cultural, and geological impacts.
Transmission is inherently prone to controversy over these criteria. First, it is long, highly visible, and has wide rights-of-way. This attracts local resistance on aesthetic, land use, and environmental grounds. Second, determining transmission needs and benefits is highly technical and controversial. Adjusting plans to account for public objections and alternative land-use considerations involves tradeoffs with economic and engineering considerations. Reconciling all competing objectives requires complex multidimensional consideration.
State policy tends to compound such problems, with a bias favoring local, low-voltage projects over multistate, high-voltage projects. Most states explicitly exempt short-distance and low-voltage lines from siting requirements. Bias manifests implicitly in several ways:
- Transmission permitting predominantly relies on public engagement to achieve siting consensus, as opposed to using eminent domain to obtain rights-of-way. While understandable, this tilts permitting outcomes toward projects with minimal objections, rather than those that maximize net benefits.
- States commonly use different benefits standards and measures and, for multistate projects, skip state-specific benefits evaluations. Despite limited information, PUCs scrutinize projects only for intrastate public need criteria and to ensure their states’ ratepayers are not subsidizing projects whose benefits accrue elsewhere. This inclines PUCs toward interstate cost allocation disputes, a common basis for rejecting permits, and away from prioritizing projects with the greatest net benefits.
- Permitting authorities act independently of one another and multistate projects must receive approvals from each state, sometimes multiple federal agencies, and a variety of localities. Projects requiring more permits across uncoordinated regulatory bodies tilts permitting to favor smaller projects across fewer jurisdictions.
Observed Effects of State Permitting on Transmission Development
Policies that suppress or distort transmission development generally reduce benefits or increase per unit costs. Customers benefit from transmission both economically and through increased reliability. A key economic benefit is congestion reduction, where the increased capacity of the transmission system enables dispatch of lower-cost power plants.
The literature and practitioners find that state permitting presents a major barrier to transmission development. Nevertheless, quantitatively measuring the effect of state-permitting laws on transmission development is exceedingly difficult. First, distinguishing state from federal permitting effects is challenging given their interdependence. This is especially true for interstate lines and lines in the West. Overall, state permitting is a greater barrier than federal permitting, which prominently affects a minority of projects.
Second, no comprehensive transmission permitting data source exists. This relegates research to often rely on anecdotal cases as evidence. A survey of policymakers, regulators, industry, and customers identified state need of certification, permitting, and siting as having stifled transmission development. Reducing barriers to state permitting is a top advocacy priority of transmission developers.
Third, isolating the effect of permitting from other regulatory factors, namely planning and cost allocation, is challenging. Altogether, regulatory factors profoundly affect the level, composition, and cost-effectiveness of transmission investment. Contemporary transmission trends reflect this:
- New transmission lines take five to 20 years to develop. Since the 2005 Energy Policy Act, new projects have taken over 10 years on average to complete. Interstate lines typically take longer to secure approvals, and there is a weak relationship between line length and project completion time.
- Reliability leads transmission rationales. Reliability was the primary driver of most (51 percent) new transmission lines over 2010-2020. The proportion of transmission circuit-miles installed to meet reliability needs grew from 44 percent to 74 percent (2011-2020). Most projects focused on incremental, not system-wide, reliability needs. The other leading drivers of new lines were load growth (9 percent) and generation at 26 percent (renewables constituted 22 percent).
- Transmission expansion investments declined. Transmission expansion investments declined consistently in the second half of last decade. The decline was particularly evident for large transmission projects, or those over 100 kilovolts (kV), with new high-capacity projects (over 230 kV) falling precipitously after 2013. The average of new high-voltage transmission miles per year dropped from 1,700 in the first half of the 2010s to 645 miles per year in the second half.
- Local transmission rose, regional projects declined. Regional transmission investment decreased 50 percent while interregional transmission remained relatively nascent last decade. From 2011-2020, 3,300 circuit-miles of new or upgraded intraregional transmission was energized, compared to 70 circuit-miles interregionally. Local transmission projects grew to constitute half of transmission investment.
- Transmission spending rose. Total transmission spending rose from $9 billion to $40 billion from 2000 to 2019, an increase of 344 percent. Since the early 2010s, the majority of spending was on new transmission. Transmission spending by investor-owned utilities rose from $20.7 billion in 2016 to $26.7 billion in 2022, an increase of 29 percent.
- Transmission needs rose. Transmission congestion costs, a key indicator of transmission need, rose an estimated $6.5 billion to $20.8 billion annually, or 220 percent, from 2016 to 2022. Most of this occurred from 2020-2022. The largest percent increase in congestion costs occurred in the Plains (614 percent), Texas (463 percent), Midcontinent (164 percent), and Mid-Atlantic (144 percent) regions from 2016-2022 (see Figure 1).
Figure 1: Regional Transmission Congestion Costs
These trends indicate several concerning underlying conditions. First, a pronounced transmission deficit—the gap between optimal need and actual expansion—is growing. This increases costs and deteriorates reliability. Second, transmission expansion needs are increasingly being met with cost-inefficient development.
These concerns are shared by those paying for transmission and benefiting from grid reliability: consumers. Research informed by transmission customers found billions of dollars in annual transmission capital allocated inefficiently. Of particular concern is an overbuild of local, lower-voltage transmission projects and underinvestment in efficient, high-voltage regional and interregional projects. Permitting is a key, but not sole, driver. In fact, U.S. high and extra-high voltage projects tend to face permitting times up to six years longer than other countries.
Suppressed high-voltage projects forgo infrastructure that can leverage the high economies of scale evident in transmission. Just 22 “shovel-ready” high-voltage transmission lines would add only 3 percent of total transmission mileage but increase system transfer capacity by 11-12 percent. Long-distance lines, especially interregional projects, increasingly help mitigate system reliability contingencies more effectively than the predominant incremental reliability projects. Longer, high-voltage lines also tend to be most advantageous environmentally; the 22 “shovel-ready” projects would reduce an estimated 131 million tons of carbon dioxide per year.
High-voltage transmission barriers have manifested most prominently in “pass-through” states, where states reject permits for a line that traverses the state but does not directly connect resources within that state. Recent scholarship suggests that the lack of quantified intrastate benefits of proposed and alternative projects deters state approvals, whereas states are more likely to grant approval when they can negotiate project alternatives that enhance benefits to their state.
Outlook
Studies project that permitting and siting challenges will restrict future transmission deployment and force alternative, higher-cost transmission solutions. Transmission spending projects will climb further; investor-owned utilities project to spend $32.1 billion in 2026, a 20 percent increase from 2022. Despite growing spending, permitting constraints project to suppress transmission expansion below the level to satisfy growing transmission needs.
In particular, studies project future economic and reliability transmission needs to outpace those of previous decades. Some analyses have found that future transmission expansion needs will exceed 2 percent per year, whereas expansion grew at 1 percent annually last decade. Projected median intraregional transmission expansion needs will increase 64 percent by 2035 under moderate-load growth and rise to 128 percent with high-load growth. Although limited interregional transfer capacity exists today, projected median interregional need increases 114 percent under moderate-load growth and 412 percent under high load by 2035. With recent load projections revised upward, it is especially important to highlight regions with the greatest relative need under a high-load growth scenario. Intraregional transmission capacity would have to more than double in the Midwest, Southeast, Texas, Southwest, Mountain, and New England. Needs in the Delta region would triple, while those in the Plains would quintuple under high-load growth.
Figure 2: Anticipated Intraregional Transmission Need in 2035
While transmission needs grow, state and local project permitting laws are trending toward becoming more restrictive for energy projects overall and, anecdotally, for transmission in particular. Developers find that federal efforts to accelerate transmission development may not be enough to overcome growing local opposition and protracted state-level study processes. It is unclear if state permitting processes will adjust to the expected increase in the number of proposals for new transmission lines.
Quantitatively, isolating the expected effects of permitting from planning and cost-allocation processes remains challenging. For example, modeling exercises suggest reforms to transmission planning, cost allocation, and permitting that may induce trillions of dollars in private investment, save consumers over $100 billion, and provide major emissions reductions by 2050. Assuming a roughly proportionate share of these benefits are attributable to permitting reform, the net economic benefits of permitting reform are in the tens of billions of dollars. There are also unquantified reliability benefits, especially for regional and interregional transmission. Transmission permitting reform also has the potential to reduce hundreds of millions of tons of carbon dioxide annually.
Although transmission regulatory flaws are multifaceted, the relative importance of state-permitting reforms is growing. Federal authorities have recently reformed interstate transmission planning and cost allocation, as well as permitting in national interest corridors. This leaves state permitting as perhaps the most impactful reform for transmission development. The undersecretary for infrastructure at the Energy Department recently remarked that permitting reform was the top priority to get transmission built.
Conclusion
Transmission development patterns reflect large regulatory inefficiencies, of which one is state-permitting practices. It suppresses transmission capacity expansion and shifts the composition of expansion toward costlier projects. The effect appears strong enough to keep transmission spending rising while suppressing expansion below critical need levels, especially with the advent of load growth. Without reform, state permitting projects to increase upward pressure on electricity costs, degrade grid reliability during severe weather events, suppress economic development by deterring load growth (e.g., data centers and manufacturers), and hamper emissions reductions.
Minimizing permitting barriers will have the greatest benefit for interstate lines in the Plains, Midwest, Mountain, and Southern regions. Interestingly, these tend to be conservative states and Republican voters favor reducing interstate transmission-permitting most. The merits follow suit, as the economic, reliability, and environmental case for state transmission-permitting reform is overwhelming.
Series: State Energy Infrastructure Permitting and Siting
Meeting electricity demands over the next few decades will require substantial infrastructure expansion throughout the energy sector. This new series surveys the challenges state and local permitting requirements pose to new energy infrastructure.