With sufficient political will, the US power sector can decarbonize by 2035, and the United States can reach net-zero emissions by midcentury—if the United States takes a comprehensive approach to planning and permitting.
The Biden administration aspires to eliminate all carbon emissions from electric power production by 2035, mainly by substituting wind and solar for coal and natural gas. And that’s just the beginning: By substituting clean electricity for fossil fuels throughout the economy, the US government aims to achieve net-zero carbon emissions by midcentury—meaning that enough carbon dioxide will be removed from the atmosphere to offset any remaining emissions from human activity. Give the president credit for audacity. The Biden administration seeks to transform the massive, capital-intensive electric power sector in a little over a decade and to reshape all US energy use in less than three. But this is not mission impossible: it’s technically feasible, even on that ambitious timeline.
One major hurdle, though, could prove a deal-breaker. Increasing the role of electricity in transportation, heating buildings, and myriad other uses will increase electricity demand more rapidly than the overall rate of economic growth—which will require a disproportionate expansion of high-voltage transmission capacity. Indeed, a slew of studies agree that achieving net-zero emissions efficiently by 2050 will depend on increasing transmission capacity by at least 150 percent and perhaps by as much as 400 percent in less than three decades.
Although annual investment in US transmission roughly quadrupled from less than $5 billion before 2005 to as much as $25 billion since 2013, the sorts of investments in transmission that are needed to decarbonize the US electric power system at reasonable cost are substantially different from most of those made in the recent past. And these investments face more serious obstacles.
Without fundamental reforms in planning and permitting, investments in cost-effective transmission can’t possibly keep up. Rapid economy-wide decarbonization still may be technically feasible, but the price tag probably would be politically unacceptable.
The Changing Role of Transmission
The Past
Shifting from fossil fuel power generation to wind and solar power generation will require significant expansion of the transmission system to connect wind and solar generators to the system, typically in areas that don’t have much preexisting transmission capacity. In the jargon of the business, this integration of power generators in the electric grid is called “interconnection.”
Historically, electric power was provided by regulated utilities or government enterprises, the only power providers in well-defined service territories. Each utility typically generated all the electricity in its service territory mainly by burning fossil fuels, delivering the power to customers over the high-voltage transmission lines and low-voltage distribution lines that it owned. The most efficient approach was to locate generators near the major demand centers.
In the 1960s and 1970s, transmission lines were built to link adjacent utilities, make electricity more reliable, and bring power from hydroelectric generators to demand centers. Regulating electric utilities was the job of state governments almost exclusively; long-distance, interregional transmission of electricity was rare.
Beginning in the late 1990s, electric power systems in many parts of the country were restructured. Power generation was decoupled from transmission, and organized wholesale markets for electricity were established.
Credit: Andrea De Santis
Seven nonprofit independent system operators (ISOs) have been established over time to manage transmission systems and supervise organized wholesale markets that meet about two-thirds of the nation’s electricity demand. The ISO that serves most of Texas, called the Electric Reliability Council of Texas (ERCOT), has only weak interconnections with the rest of the nation for political reasons; accordingly, the Federal Energy Regulatory Commission (FERC) has authority over all transmission systems other than ERCOT.
To encourage competition among generation companies in wholesale electricity markets, FERC issued Order 888 in 1996. This regulation requires transmission operators to allow all generators to connect to ISO systems on nondiscriminatory terms. But new generators are required to fund new lines and reinforcements to existing lines for reliability purposes. So long as the need for new connections was limited to a relatively small number of fossil fuel–powered generators near demand centers, this process was relatively smooth.
The Present
Everything changed at the turn of this century. Investment grew in wind and solar power generation, thanks to a combination of federal subsidies, new mandates in many states for wind and solar energy, and dramatic declines in the cost of wind and solar power generation. Old fossil fuel–powered generators, particularly the large coal-fired plants that had dominated production for decades, began to retire.
This rise in wind and solar power complicated the interconnection process in two ways. First, utility-scale wind and solar power generators require lots of space and thus are located far from where demand is concentrated. But rural areas don’t have much preexisting transmission capacity; connecting a new wind or solar generator in remote places often requires expensive upgrades to the transmission system. Moreover, connecting offshore wind generators involves building completely new undersea transmission networks and reinforcing the onshore transmission system.
Second, utility-scale wind and solar generators tend to produce less electricity than the fossil fuel–powered generators they’ve replaced. As a result, the number of connections between generators and transmission systems has needed to increase to deliver the same amount of power. In 2022, for instance, 614 new, relatively small generators replaced 166 retired utility-scale generators, though total generating capacity stayed essentially the same.
For the transmission system to facilitate decarbonization at reasonable cost, the system must be able to span long distances. The quality of wind and power resources varies substantially from region to region, with the cost of solar generation lowest in the southwestern United States and the cost of wind generation lowest in the middle of the country. Moreover, because regional shifts in cloud cover and wind can rapidly change geographic patterns in the availability of solar and wind power, interregional connections can enhance overall reliability, increase the supply of energy, and reduce the average cost of power. Consequently, long-distance transmission of electricity (particularly interstate) has much greater value in systems that are dominated by solar and wind energy, compared to systems that run primarily on fossil fuels. Planning investments in long-distance transmission at the national level will be necessary for an efficient, reliable national grid; however, no government entity has responsibility or authority for national-level transmission planning.
Despite their growing importance, new long-distance transmission lines are becoming increasingly rare. The installation of very high-voltage transmission lines (above 345,000 volts, suitable for moving power efficiently across hundreds of miles) declined from 1,700 miles per year in the first half of the 2010s to an average 645 miles per year in the second half of that decade. Only 567 miles were completed in 2021, and only 198 miles were constructed in 2022.
Throughout the country, long and growing queues await connection to the transmission system for projects related to wind power, solar power, and related energy storage. By the end of 2022, about 10,000 projects had applied for connection to the transmission grid.
The Interconnection Problem
Under FERC Order 845, issued in 2018, utility-scale generation and storage facilities that seek to connect to the transmission grid must make an interconnection request to the relevant transmission operator, which in much of the country will be an ISO. Facilities get added to the queue in the order in which they apply. After a sequence of studies, each facility applicant is told what it must pay to be connected. If an applicant agrees to accept the final assessed cost, an interconnection agreement is signed, and the transmission upgrade can go forward.
Connecting generation capacity at one point may require upgrades to relatively distant transmission lines. So, the process of assessing any particular project’s interconnection costs can be quite complex—and easily disputed.
Applicants can withdraw from this process at any time and at little cost. So, a project developer has strong incentives to submit multiple interconnection requests for different interconnection points as early as possible. Applicants can simply walk away for any reason.
Credit: Andrea De Santis
Between 2014 and 2022, interconnection requests nationwide increased by a factor of four in terms of generating capacity. At the end of 2022, the total proposed capacity of projects with active interconnection requests represented 163 percent of the capacity of the entire US power system! Most of those proposed projects will never get built. Of the requests made in 2000–2017, only 14 percent (in terms of capacity) were completed by the end of 2022, in large part because most project applications were withdrawn. Fully 71 percent of the interconnection requests made in 2014–2017 were withdrawn by the end of 2022.
These withdrawals slow everything down. When one project’s interconnection request is withdrawn, the costs of connecting the projects that follow in the queue typically need to be reexamined. Numerous withdrawals in recent years, along with a scarcity of staff that have the relevant expertise, have contributed to increases the median time between interconnection request and interconnection agreement from less than 20 months in 2015 to around 35 months in 2022.
Recent Response from the Federal Energy Regulatory Commission
Under FERC Order 2023, adopted in July last year, eligibility for an interconnection agreement requires a developer to already have the right to build on the site it proposes to use and to post a deposit. Developers then may apply to be included in a cluster of projects that get studied together, with the aim of reducing repetitive reevaluations of costs. Order 2023 also provides general rules for the allocation of interconnection costs among members of a cluster. Transmission providers are obligated to show developers where interconnection capacity is available without major upgrades to the system, and the providers must meet strict deadlines for study completion.
Investment grew in wind and solar power generation, thanks to a combination of federal subsidies, new mandates in many states for wind and solar energy, and dramatic declines in the cost of wind and solar power generation.
Nationwide implementation of Order 2023 likely will shrink the queues of interconnection requests. But this policy ensures that the interconnection process will remain purely reactive and incremental, making it a poor vehicle for efficient expansion of the nation’s transmission system. Moreover, transmission providers that have adopted many of the reforms in Order 2023 nonetheless still have queues.
Alternative Approach to Interconnection
A better way is possible. An alternative, proactive process was applied in the highly successful Competitive Renewable Energy Zones (CREZ) transmission project in Texas.
In 2002, the Texas legislature ordered the Public Utility Commission of Texas to plan and supervise the construction of transmission lines to meet growing electricity demand by enabling dramatic increases in wind generation. The costs of the new lines were borne collectively by all Texas ratepayers. The Public Utility Commission of Texas identified a small number of “renewable energy zones” in rural areas with good wind resources, plenty of cheap land, and developer interest in building wind farms. By March 2009, regulators decided on the new high-voltage transmission lines and designated the builders, with technical support from ERCOT and with input from stakeholders. The new lines went into service rapidly, by January 2014, which dramatically reduced the interconnection costs for wind generators.
These CREZ lines constituted 23 percent of all the high-voltage lines built in the United States in 2008–2020 and involved proactive regional transmission planning in advance of specific generation proposals. Wind-generation capacity in Texas increased by a factor of 12 in 2005–2020, with much of that new capacity built after the CREZ lines were in service. The process was greatly simplified by the decision to distribute the costs of the new high-voltage lines across all Texas ratepayers and by granting authority to a single agency (the Public Utility Commission of Texas) with the power of eminent domain.
Other ISOs have begun to follow this model of planning the expansion of transmission lines to accommodate the new power generation that’s expected.
The Long-Distance Problem
The SunZia Wind and Transmission Project illustrates the magnitude of the problems related to planning and permitting that stand in the way of building critical long-distance transmission lines.
In 2006, SunZia was proposed as a stand-alone “merchant” transmission project, meaning that it was conceived as an unregulated project without a guaranteed return on developer investment. In May 2023, the project received final federal approval for construction to begin. Construction began on September 1, but work on a 50-mile segment was suspended in early November in response to complaints by Native nations in Arizona. When SunZia ultimately becomes operational, it will be the largest wind project in the Western Hemisphere, with 550 miles of high-voltage transmission lines that will connect wind-generating rural counties in New Mexico to demand centers in Arizona.
Perhaps SunZia would have emerged from a comprehensive regional planning process—but probably not. A set of stand-alone projects, each designed to be economically viable and to elicit the necessary political support, is unlikely to add up to an efficient regional system. Interregional negotiations are even more complex, and successful negotiations are quite rare. Whereas FERC can compel planning—and it has done so with Order 890 in 2007 and Order 1000 in 2011—the agency cannot compel agreement within a reasonable time. And without agreement, nothing gets built.
Compounding these problems is the multiplicity of FERC-defined regions for transmission planning, each of which is responsible primarily for intraregional transmission. The contiguous United States contains 12 such regions: the seven ISOs mentioned above and five other regions, mainly in the West and Southeast, that lack an ISO responsible for managing the regional transmission system. The boundaries of these 12 regions generally do not coincide with state lines, several regions are not contiguous, and state governments generally are not involved in transmission planning. An efficient nationwide system with appropriate long-distance interstate transmission is unlikely to result from such a geographically fragmented system that’s focused almost exclusively on intraregional transmission.
Credit: Dietrich Leppert / Shutterstock
In 2005, a prescient US Congress attempted to bulldoze the barriers of this decentralized approach by empowering the US Department of Energy to designate National Interest Electric Transmission Corridors. If a state failed to approve a proposed transmission project in one of these corridors in a timely fashion, FERC would have the authority to coopt the project. But the courts effectively gutted this authority, which has been moribund since 2011. In 2021, the law was amended to give FERC siting authority for corridor projects that had been rejected by one or more states. The Department of Energy and FERC currently are developing rules that will govern this newly revived process. This project-by-project siting authority may enable some beneficial projects to go forward that otherwise would be blocked. But this backstop law is no substitute for systematic nationwide planning and siting.
The contrast between the system in the United States and the system in the European Union is dramatic. In the European Union, an expert agency called the European Network of Transmission System Operators for Electricity prepares development plans that span 10-year periods and the entire European Union. The agency has the authority to accelerate important projects that cross national borders.
The permitting problem for long-distance projects like SunZia may be at least as important and difficult to solve as the problem of planning an efficient national transmission system. Getting the permits to allow SunZia to begin construction in 2023 reportedly required 17 years and involved 10 federal agencies, 5 state agencies, and 9 local authorities. Moreover, the route of the transmission lines was changed many times in response to local, state, and national stakeholders, becoming circuitous in the process. The implications are ominous: if a long-distance transmission line proposed in 2023 could not even begin construction until 2040, then decarbonization will happen much too late for the United States to reach its midcentury goal.
Singkham / Shutterstock
17 years
Amount of time for the SunZia Wind and Transmission Project to get the permits needed before beginning construction in 2023
Another source of long delays is lawsuits that charge environmental violations. The issue is not whether the lawsuits filed against any project have merit; serious claims that a project violates environmental laws deserve their day in court or before a federal regulator. The problem is that the current permitting regime does not require all such claims to be presented and evaluated within a reasonable time frame. Unless resolving challenges to major infrastructure projects becomes possible in a timely fashion, the United States may not be able to build the transmission grid that’s necessary before midcentury.
Policy Solutions for the Long-Distance Problem
The US Congress took a small step toward solving the permitting problem with the Fiscal Responsibility Act of 2023, which sought to streamline and place time limits on project reviews under the National Environmental Protection Act. But even if these reforms are effective, infrastructure projects will remain vulnerable to long delays caused by lawsuits that are based on other environmental statutes.
The Biden administration seems to recognize the need for broader permitting reform. In May last year, the White House announced a plan to coordinate transmission-line permitting among six cabinet-level departments and three other agencies, with the Department of Energy designated as the lead agency for environmental review. Such coordination could prove especially valuable in the western United States, where federal land use largely is at issue. Days later, the White House posted a long list of priorities for permitting reform. These priorities would be a fine point of departure for legislation.
FERC’s recently reinvigorated backstop siting authority, which works on a project-by-project basis, is no substitute for an expert planning agency with nationwide scope. The ongoing National Transmission Planning Study, overseen by the Department of Energy, covers the entire contiguous United States and could be the seed for such an agency.
Uncrossing the Wires
While FERC’s recent Order 2023 may help shorten interconnection queues and reduce the repetitive reevaluation of proposed interconnections, the approach remains fundamentally reactive and incremental. As a result, costs will be higher than they could be if transmission providers would follow the CREZ model and proactively build high-capacity lines that can integrate wind and solar power generation. Several ISOs are moving in this direction. Another helpful move would be for FERC to require all regional transmission managers to follow suit.
Business as usual clearly cannot produce an efficient national transmission system; comprehensive interregional planning is necessary. But despite FERC’s initiatives, such planning is rare, and plans that cover more than one FERC region do not exist. As in the European Union, a single agency with the power and responsibility to get the job done would help—and would require a substantial concentration of authority. Even with such an agency, the permitting delays for long-distance interregional transmission lines would remain a formidable barrier.
With sufficient political will, the US power sector can decarbonize by 2035, and the United States can reach net-zero emissions by midcentury. But without a fresh and comprehensive approach to planning and permitting, the cost of reaching these goals will be much higher than necessary—and the political barriers accordingly will be more daunting.
A version of this Resources magazine article was first published in the Milken Institute Review.
A version of this article appeared in print in the Spring 2024 issue of Resources magazine.
