Unless you’ve devoted 2023 exclusively to bingeing Suits reruns, you probably know that 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 White House aims to achieve net-zero carbon emissions by 2050 – meaning that enough CO2 is removed from the atmosphere to offset any remaining emissions from human activity.

Give the president credit for audacity. The administration seeks to transform the massive, capital-intensive electric power sector in a little over a decade and to reshape all U.S. energy use in less than three. But this is not mission impossible. Most analysts have concluded it is technically feasible to get from here to there at warp speed. However, one major hurdle – a hurdle that has received relatively little attention – could prove a deal-breaker.

Increasing the role of electricity in transportation, heating buildings and myriad other uses will, of course, increase electricity demand more rapidly than the overall rate of economic growth – and that will entail a disproportionate expansion of high-voltage transmission capacity to move the power from where it is generated to where it is needed. Indeed, a slew of studies agree that achieving net-zero emissions by 2050 efficiently will depend on increasing transmission capacity by at least 150 percent and perhaps by as much as 400 percent in less than three decades.

A casual look at recent history suggests that such a dramatic expansion in transmission capacity would not be all that difficult. Government-mandated investments in transmission in the U.S. typically earn generous rates of return. And annual investment in U.S. transmission roughly quadrupled from less than $5 billion before 2005 to $20-25 billion since 2013.

But don’t pop the champagne corks just yet. Because of the growing importance of variable renewable energy, or VRE, generation (the catchall term for wind and solar), the sorts of investments in transmission needed to decarbonize the U.S. electric power system at reasonable cost are systematically different from most of those made in the recent past. And they face more serious obstacles. Indeed, without fundamental reforms in planning and permitting, investments in costeffective transmission can’t possibly keep up. Rapid economy-wide decarbonization might still be technically feasible, but the price tag would probably be politically unacceptable.

The Changing Role of Transmission

Set aside the inevitable increase in total demand for electricity to displace all the uses of coal, oil and natural gas. Simply shifting from fossil generation to VRE generation will require significant expansion of the transmission system to perform new, related functions. First, investment will be required to connect numerous, often relatively small VRE generators to the transmission system, typically in areas without significant pre-existing transmission capacity. In the jargon of the business, this is called the “generation interconnection” function.

Historically, electric power was provided by regulated utilities or government enterprises that were the only providers in welldefined service territories. Each typically generated all the electricity that was consumed in its service territory and delivered it to customers over high-voltage transmission lines and low-voltage distribution lines that it owned. Most generators were fossil-fueled, and it was usually efficient to locate them relatively near major demand centers. In the 1960s and 1970s, transmission lines were built to link adjacent utilities to make the systems more reliable and to bring power from a few humongous hydroelectric generators to demand centers. Electric utility regulation was almost exclusively the job of state governments; long-distance, interregional transmission of electricity was rare.

Beginning in the late 1990s, though, electric power systems in many parts of the country were restructured, with the business of generation separated from the business of transmission and the establishment of organized wholesale markets for electricity. Seven nonprofit independent system operators (ISOs) have grown over time to manage transmission systems and to supervise organized wholesale markets that meet about two-thirds of the nation’s electricity demand. For those of you willing to dive into the details, here’s the dance card:

• New York ISO serves New York State.
• ISO New England serves the six New England states.
• California ISO serves most of California.
• Electric Reliability Council of Texas (ERCOT) serves most of Texas.

The other three ISOs have complex boundaries:

• Midcontinent ISO (MISO) and Southwest Power Pool (SPP) each serve all or parts of 15 states.
• Pennsylvania-New Jersey-Maryland Interconnection (PJM) serves all or part of 13 states.

Roughly, MISO’s territory runs from Minnesota south to Louisiana, SPP borders MISO to the west, and PJM’s territory runs mostly west from its three founding states. ERCOT has only weak interconnections with the rest of the nation for political reasons. Accordingly, it is not subject to federal regulation.

To encourage competition among generation companies in wholesale electricity markets, the Federal Energy Regulatory Commission (FERC), which has authority over transmission systems other than ERCOT, issued Order 888 in 1996. This required transmission operators to allow all generators to connect to their systems on nondiscriminatory terms. But new generators were required to pay for new lines as well as for reinforcements to existing lines needed for the system to maintain reliability. And as long as a relatively small number of large fossil-fueled generators located near demand centers needed new connections, this process was relatively smooth.

But all that changed beginning in the first decade of this century. Thanks to a combination of federal subsidies for VRE generation, the imposition of VRE mandates by many states and dramatic declines in the cost of wind and solar generation, investment in VRE generation grew rapidly. By no coincidence, old fossil-fueled generators, particularly the large coal-fired plants that dominated production for decades, began to be retired.

This complicated the interconnection process in two ways. First, VRE generators large enough to be connected to the transmission system (i.e., utility-scale wind and solar) require lots of space and thus are located far from where demand is concentrated. But connecting a new VRE generator in a rural area where there is not much pre-existing transmission capacity often requires expensive upgrades to the transmission system. Meanwhile, connecting offshore wind generators, which will almost certainly play a major role in decarbonization, involves building completely new undersea transmission networks as well as reinforcing the onshore system. Consider, too, that utility-scale VRE generators tend to produce less electricity than the fossil generators they replace, so the required number of connections between generators and transmission systems increases in order to deliver the same amount of power. During 2022, for instance, 166 utility-scale generators were retired to be replaced by 614 generally smaller new generators, while total generating capacity was essentially unchanged.

The second new job that the transmission system must perform to enable decarbonization at reasonable cost is the “long-distance” function. The quality of VRE resources varies substantially from region to region, with the cost of solar generation lowest in the Southwest and the cost of wind generation lowest in the middle of the country. Moreover regionwide shifts in winds and cloud cover change geographic patterns of VRE generation availability very rapidly, so interregional connections serve to enhance overall reliability as well as to increase supply and reduce the average cost of power. As a consequence, longdistance (particularly interstate) transmission of electricity has much greater value in VREintensive systems than in fossil fuel-dominated systems. So planning long-distance transmission investments at the national level is necessary if an efficient, reliable nationwide grid is to be constructed.

The history of natural gas transmission is instructive. By the 1930s it had become clear that the nation would benefit enormously from piping natural gas from the Southwest to demand centers in the Northeast. To facilitate this, the Federal Power Commission (later renamed the Federal Energy Regulatory Commission, or FERC) was given authority in 1938 to license interstate natural gas pipeline routes, along with the power of eminent domain to facilitate acquisition of rights-of-way. Interstate transmission of electricity had less potential value then, and neither FERC nor any other federal agency has even been given comparable sweeping authority to authorize the construction of electricity transmission lines that cross traditional regional boundaries. Moreover, no entity has responsibility or authority for national-level transmission planning.

As noted earlier, the U.S. has nonetheless invested heavily in electricity transmission in recent years. But a close look reveals that most of the post-2005 surge in investment was in local or regional projects undertaken in a single provider’s service area to enhance reliability or to replace aging equipment – not to perform either the generator interconnection function or the long-distance function. Regulators are generally sympathetic to local projects. Interregional projects are a different story.

Throughout the country there are long and growing queues of proposed VRE generation and complementary electricity storage projects that have applied for connection to the transmission grid – about 10,000 projects at the end of 2022. Note, too, that the installation of very-high-voltage (above 345,000 volts) transmission lines – the sort of lines that are 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 of 645 miles per year in the second half of that decade. Only 567 miles were completed in 2021, and only 198 miles in 2022. Thus despite their growing importance, new long-distance transmission lines are becoming increasingly rare.

The Generator Interconnection Function

Under FERC’s Order 845 issued in 2018, utility- scale generation and storage facilities that seek to connect to the transmission grid must make an interconnection request (IR) to the relevant transmission operator – an ISO in much of the country. They are added to the queue in the order in which they apply. After a sequence of studies, each applicant is told what it must pay to be connected.

Because the transmission system is a web, not a point-to-point system, and electrons flow along multiple paths within it, connecting generation capacity at one point may ultimately require upgrades to relatively distant lines. So the process of assessing any particular project’s interconnection costs can be quite complex – and easily disputed. If after the studies an applicant agrees to accept the final assessed cost, an interconnection agreement (IA) is signed, and the transmission upgrade can go forward.

Now, an applicant can withdraw from this process at any time and at little cost. So a project developer has strong incentives to submit multiple IRs for different interconnection points as early as possible, particularly if the grid may early-on be able to accommodate a few projects without upgrades. If for any reason a project’s assessed interconnection cost turns out to be too high for the project to be viable – or if the developer cannot acquire the land it needs, or if it cannot find a buyer for the power it plans to produce – it can simply walk away.

Though a number of ISOs have been allowed to tighten the requirements of this freefor- all, the generation interconnection process has nonetheless widely broken down. Between 2014 and 2022, interconnection requests nationwide (measured by generating capacity) increased by a factor of four. Indeed, at the end of 2022 the total proposed capacity of projects with active IRs was 163 percent of the total capacity of the entire U.S. power system.

Most of those proposed projects will never be built; of the requests made between 2000 and 2017, only 14 percent (by capacity) resulted in completed projects by the end of 2022. The main reason is that most are withdrawn. In fact, fully 71 percent of the IRs made between 2014 and 2017 were withdrawn by the end of 2022.

Oh, the tangled webs we weave (literally). When one project’s IR is withdrawn, the upgrades and costs of connecting the projects that were behind it in the queue typically need to be re-examined. The re-examinations made necessary by the numerous IR withdrawals in recent years, along with the scarcity of staff with the relevant expertise, have played a role in increasing the median time between an IR and the issuance of an IA from less than 20 months in 2015 to around 35 months in 2022.

The regulators understood all this was untenable, and they have sought to minimize the number of IRs that amounted to gaming the system. Under FERC Order 2023 adopted last July, to be considered for an IA a developer must already have the right to build on the site it proposes to use and must post a deposit. During announced windows, developers may then apply to have their projects included in a cluster of projects that will be studied together, hopefully reducing repetitive re-evaluations of costs. Order 2023, moreover, short-circuits another time-wasting issue by providing 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 and must meet strict deadlines for study completion.

Nationwide implementation of Order 2023 should shrink the IR queues. It is worth noting, though, that transmission providers who have adopted many of its reforms nonetheless still have long queues. In any case, under Order 2023 the interconnection process will remain purely reactive and incremental, making it a poor vehicle for efficiently expanding the nation’s transmission system.

There’s a better way. An alternative, proactive process was followed 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 construction of transmission lines that would enable dramatic increases in wind generation to meet growing demand. The costs of the new lines were to be borne collectively by all Texas ratepayers.

The PUCT then 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. With technical support from the Texas ISO and with input from many stakeholders, the regulators decided on the new high-voltage transmission lines and designated their builders by March 2009. By January 2014, all the new lines were in service. The new lines not only went in rapidly, they dramatically reduced wind generators’ interconnection costs.

These lines constituted 23 percent of all the high-voltage lines built in the U.S. from 2008 to 2020. Wind generation capacity in Texas increased 12-fold between 2005 and 2020, and much of that new capacity was built after the CREZ lines were in service.

In contrast to the reactive processes prescribed by FERC orders, the CREZ project involved proactive regional transmission planning in advance of specific generation proposals. The decision to spread the costs of the new high-voltage lines over all Texas ratepayers greatly simplified the process, as did having a single agency with the power of eminent domain in charge.

There are obvious advantages to CREZ like interconnection processes, in which regional transmission expansion is planned to accommodate new generation that would be expected if interconnection costs were reduced. Generators would then be assessed the lower costs of connecting to the expanded grid. The other big independent system operators have begun to follow Texas’ lead. I think that FERC should take a leaf from Texas’ book, shifting to a proactive process that speeds generator interconnection nationwide.

The Long-Distance Function

A closer look at one case, the SunZia project, illustrates the magnitude of the problems of planning and permitting that stand in the way of building the long-distance transmission lines critical to a cost-effective, reliable VRE dominated system.

It’s not all bad news. In May 2023, this project received the final federal approval necessary for construction to begin. If all goes as planned, SunZia will become operational in 2026, and it will include the largest wind project in the Western Hemisphere along with 550 miles of high-voltage transmission lines that will connect wind-generating rural counties in New Mexico to demand centers in Arizona.

Planning. SunZia was not an outcome of a regional planning process. It was initially proposed as a stand-alone, “merchant” transmission project (i.e., an unregulated project that does not have a regulator-guaranteed return to its developer’s investment) in 2006. If the project had only consisted of the transmission line, it would have served to raise electricity prices in New Mexico and lower them in Arizona, making New Mexico’s support unlikely. But by including a massive wind project in New Mexico, the developer could promise local jobs and tax revenues.

SunZia might have emerged from a comprehensive regional planning process – but probably not. Operating a new transmission line typically affects power flows on existing lines. These externalities, plus the diverse interests affected by long-distance transmission projects, suggest that 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.

FERC has long recognized the value of regional and interregional transmission planning. Its Order 890 in 2007 required transmission providers to have approved transmission planning processes, while another order in 2011 required all transmission providers to participate in regional planning and interregional coordination.

FERC, moreover, specified that the costs of transmission projects be allocated so that they are “roughly commensurate” with the benefits received. And in April 2022, FERC issued a tentative rule that would require planners to consider, among other matters, the broad societal benefits that proposed transmission projects could deliver over 20 years and to engage the states in each planning region in devising how the costs were allocated.

Unfortunately, while the rule may improve transmission planning, it will not address several fundamental problems. These are paradoxically illustrated by issues left unaddressed in a major regional planning success: the approval in July 2022 by the Midcontinent Independent Service Operator (MISO) of a $10.3 billion transmission expansion plan that includes 18 very-high-voltage projects in nine states in MISO’s northern and central regions. MISO’s documents show that this plan, broadly comparable in scale to the CREZ project in Texas, will produce positive net benefits for all affected subregions and will enable the interconnection of a whole lot of new VRE generation. The approval, the result of a regional process that seems largely to have conformed to FERC’s proposed rule, shows that such processes can sometimes work.

But it’s worth noting what the MISO project does not accomplish. The plan does not provide for transmission expansion in its southern region. Nor does it provide for strengthening the weak link between that subregion and the rest of MISO. In general, there is no guarantee that a planning process that involves multiple stakeholders will lead to agreement on both technical and costsharing issues. FERC can compel planning, but it cannot compel agreement on these issues in a reasonable time. And without agreement, nothing gets built.

Note, moreover, that none of the 18 projects in MISO’s expansion plan cross MISO’s boundaries. This is not because there are no potentially attractive cross-boundary projects in sight. An interim report from the Department of Energy concluded that, for the whole country, “The highest density of [high-value] transmission additions occurs between the wind belt and eastern interconnection demand centers.” And the wind belt extends well to the west of MISO’s territory.

However, Chicago, a major demand center, is not in MISO’s territory, and other important demand centers lie to the east of MISO’s territory. Interregional negotiations are much more complex than even the nine-state negotiations within MISO’s north and central regions, and successful interregional negotiations are quite rare.

Compounding these problems is the multiplicity of FERC-defined transmission planning regions – each, like MISO, primarily responsible for intraregional transmission. There are 12 such regions in the contiguous U.S.: the seven ISOs described above along with 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, and several regions are not contiguous.

It would be miraculous if such a geographically fragmented planning process, focused almost exclusively on within-region transmission, somehow led to an efficient nationwide system with appropriate long-distance, interstate transmission.

In 2005 a prescient Congress attempted to bulldoze the barriers created by this decentralized, regionally focused approach by empowering the Department of Energy to designate National Interest Electric Transmission Corridors. If a state failed to approve a proposed transmission project in timely fashion, FERC would have the authority to co-opt it. But the courts effectively gutted this authority, and it has been moribund since 2011.

Then, in 2021, the law was amended to give FERC siting authority for NIETC projects that had been rejected by one or more states, and regulators are in the process of developing the rules that will govern this newly revived process. This project-by-project backstop siting authority may enable some obviously beneficial projects that would otherwise be blocked to go forward. But it is no substitute for systematic nationwide planning and siting.

Europe, often ridiculed for its ponderous bureaucracies, sometimes just does it better. The European Union has developed a radically different planning process. An expert agency (ENTSO-E, for those collecting acronym salad) receives proposals from transmission system operators, project developers and others, applies a benefit-cost analysis that considers multiple benefits from those proposals, and drafts a 10-year EU-wide transmission development plan every two years. That plan is reviewed and finally approved by the European Commission.

Projects in the approved plan that have significant impact in more than one EU country are designated “projects of common interest” (PCIs). The countries primarily affected by a PCI have a limited time to reach agreement on how to share its cost. If they don’t agree, the EU-wide electricity regulator (the Agency for the Cooperation of Energy Regulators, ACER, in case you really want to know) makes a binding decision. In some instances, the European Commission will cover some of the cost.

Obviously, the EU framework cannot simply be imported intact to the U.S., but its basic architecture suggests the potential value of an expert planning agency with nationwide scope. The ongoing National Transmission Planning Study overseen by the Department of Energy, which covers the entire contiguous U.S. though not at the project-specific level of detail, could be the seed for such an agency. The European model also suggests a substantially increased role for state governments, rather than ISOs or other entities with fewer regulatory and fiscal tools, in planning longdistance transmission projects and developing cost-sharing agreements.

Permitting. The permitting problem for long-distance projects like SunZia may be at least as important and as 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 to reach agreement from ten federal agencies, five state agencies and nine local authorities. Moreover, the transmission line’s (now circuitous) route was changed many times in response to local, state and national stakeholders. The implications are ominous: if a long-distance transmission line proposed in 2023 could not even begin construction until 2040, it would be much too late to contribute to rapid decarbonization.

Unlike natural gas pipelines, there is no designated lead federal agency that could solicit comments from affected stakeholders, approve SunZia’s route and invoke the power of eminent domain to ensure that needed land could be acquired on reasonable terms. From time to time, federal legislation has been proposed that would give FERC roughly the same authority for major interstate transmission lines as it now has for natural gas pipelines. But these proposals have not attracted strong support.

In any event, such authority would not be a magic bullet. In fact, as the saga of the Mountain Valley gas pipeline makes clear, it might not make a big difference. This 303- mile project was initially proposed in 2014, and FERC gave the green light three years later. But numerous lawsuits were filed charging environmental violations, and the commission ordered construction halted in 2019, when the project was 93 percent complete. Then, despite an act of Congress ordering the issuance of all necessary permits, it took a Supreme Court decision in July 2023 to allow construction to resume.

The question is not whether the lawsuits filed against this pipeline (or any other infrastructure 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 that all such claims be presented and evaluated in reasonable time. Unless it somehow becomes possible to resolve all challenges to major infrastructure projects in a timely fashion, it may just not be possible to build the transmission grid we need before mid-century.

Congress took a small step in this direction in 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 still be vulnerable to long delays caused by lawsuits based on other environmental statutes.

The Biden administration seems to recognize the need for broader permitting reform. Last May, the White House announced a plan to coordinate the actions of the six Cabinet level departments and three other agencies potentially involved in transmission line permitting, with the Energy Department as the lead agency for environmental review. Such coordination could prove especially valuable in the West, where federal land use is at issue. And days later, the White House posted a long, broadly sensible list of priorities for permitting reform. It would be a fine point of departure for legislation.

Uncrossing the Wires

While FERC’s recent Order 2023 may serve to shorten interconnection queues somewhat and reduce the repetitive re-analysis of proposed interconnections, FERC’s approach will remain fundamentally reactive and incremental. As a result, costs will be higher than they could be if transmission providers would follow the Texas model and proactively build high-capacity lines where they will be needed. As noted above, several ISOs are moving in this direction. FERC should require all regional transmission managers to follow suit. It should be plain by this point that business- as-usual cannot produce an efficient national transmission system. Comprehensive interregional planning is a must. And, despite FERC’s initiatives, such planning is still rare, and plans covering more than one region really do not exist. We need a single agency with the power and responsibility to get the job done. And that would require very substantial concentration of authority. For even if we could develop nationwide transmission plans similar to the EU-wide plans, the permitting delays for long-distance interregional transmission lines would remain formidable barriers.

With sufficient political will, the electric power system can be decarbonized by 2035, and the U.S. will reach net-zero emissions by 2050. But without a fresh start at planning, the cost of reaching these goals will be much higher than necessary. And the task of getting from here to there will be yet more daunting.

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Ironies abound here. Not so long ago, the ease with which interest groups could slow or even stop major infrastructure projects was seen as a vital tool in environmentalists’ repertoire. For that matter, it often still is, as battles over oil pipelines suggest. But the struggle to build a national grid able to support the rapid electrification of the American economy is, in effect, the mother of all environmental battles. And it would be a pity if America lost that battle because it could not adopt comparatively straightforward regulation that made it possible to put the national interest first.