By Jeff St. John
Over the past nine months, the Federal Energy Regulatory Commission has been working on a major reform to U.S. transmission-grid policy, one that clean-energy advocates say could determine whether or not the country will be able to build the vast amount of solar and wind power needed to combat climate change.
On Thursday, FERC approved the first fruits of that process — a proposal to require transmission providers to develop new planning processes and draw up 20-year plans for building large-scale regional transmission and sharing the costs. The aim is to build a grid robust enough to handle a rapidly changing energy mix over decades to come.
FERC’s notice of proposed rulemaking (NOPR) doesn’t directly address some factors holding back clean-energy growth. For example, it doesn’t propose policies specifically aimed at reducing interconnection queue backlogs and costly grid upgrades for wind, solar and energy-storage projects — issues that the agency intends to take up in a future proposed rulemaking.
But the NOPR has earned cautious approval from clean-energy backers like the American Clean Power Association trade group for laying the groundwork for building the kind of grid the country will need to capture the cost, reliability and decarbonization benefits of clean energy.
“Clean energy resources are abundant in the U.S., but our grid falls short of connecting clean-energy-rich regions to the population centers that need it most,” American Clean Power CEO Heather Zichal said in a Thursday statement. “We encourage FERC to refine and finalize today’s proposal so that current and anticipated transmission needs can be met in a timely and cost-effective manner and support a transition to a clean energy future.”
Thursday’s 4–1 vote approving the NOPR is only the first step in this process. Stakeholders — including transmission grid operators, state utility and energy regulators, transmission-owning utilities, independent transmission and energy developers — will have months to comment on the proposal and debate how planning should be conducted. Then FERC will vote on a final rule, potentially before the end of this year.
What FERC’s proposed rule would do
As laid out in Thursday’s NOPR, all regulated transmission providers would be required to undertake planning in a “sufficiently long-term, forward-looking basis to meet transmission needs driven by changes in the resource mix and demand.” These “Long-Term Regional Transmission Planning” processes would be required to look at least 20 years ahead when considering the new generation resources and loads they’ll need to serve.
They would also need to consider a number of factors in determining the benefits of regional transmission plans to be weighed against the costs of building them. Those include federal, state and local clean-energy and decarbonization mandates, as well as the underlying economic factors that are leading to a shift from fossil fuels to lower-cost renewable resources. They also include growing power demand from electric vehicles and building heating systems, and “high-impact, low-frequency events such as extreme weather,” according to FERC’s synopsis of the 475-page proposal.
All in all, this is a much broader set of potential benefits than those that are now considered in the relatively limited reliability and economic analyses that guide many transmission planning processes today.
For many transmission projects, allowing a broader set of benefits to be tallied as part of a cost-benefit analysis can make the difference between being deemed cost-effective enough to proceed and being deemed too costly. This is illustrated in the following chart from a 2021 analysis by consulting firm Brattle Group, which shows how benefits stacked up for a number of past transmission proposals.
This also means that plans that take such benefits into account are likely to yield transmission investments that are broader in scope and more costly to build in the short run, even if the long-term benefits eventually outweigh those costs.
This could raise tensions with the state regulators that hold authority over siting transmission projects within their borders and are responsible for ensuring that their costs don’t exceed their benefits.
State-regulated utilities — and their customers — will shoulder the costs of building new transmission, typically in the form of increases in the shared transmission tariffs assigned for the portion of electricity they receive from the grids in question.
To mitigate this potential for conflict, FERC’s proposal would require state approval of the cost-allocation methods developed through these regional planning efforts. This requirement emerged from a task force set up last year that brought together FERC and state utility regulators to hash out the key issues that have pitted states against the transmission plans developed by federally regulated transmission operators.
Some transmission boosters have called for the federal government to use eminent domain powers to override state and local opposition to transmission projects. But others have warned against pushing projects that can’t gain state-level support, arguing that engaging state regulators and utilities is far more likely to yield plans that can successfully navigate the kinds of regulatory and legal challenges that have forced many projects to be abandoned over the past decade.
All together, the NOPR represents “a product of a lot of discussion and a lot of compromise,” FERC Chair Richard Glick, who launched the review of transmission policy in July 2021, said at Thursday’s meeting. The overarching goal is to establish a new regulatory structure that fairly distributes costs and benefits of a transmission buildout that “will address our nation’s changing resource mix and the changing role of electricity in society,” he said.
That’s not happening under FERC’s existing regulatory structures, Commissioner Allison Clements said at Thursday’s meeting. “Americans pay billions of dollars annually extra due to transmission congestion,” she said. “Extreme weather and disasters are testing a system not planned for these emerging conditions,” and roughly 1.4 terawatts of solar, wind and energy-storage projects are “stuck in queues around the country, unable to provide largely lower-cost electricity.”
Why today’s grid-planning paradigms need fixing
This view is backed up by numerous studies warning of the negative impacts of the slowing pace of transmission development across the country. Those include rising costs from grid congestion preventing low-cost energy from reaching population centers where it can be used, as well as increasing waits and interconnection costs for clean energy projects seeking to interconnect to the grid.
“That level of a logjam is reflective of the fact that our transmission system is basically full,” Robert Gramlich, executive director of Americans for a Clean Energy Grid, said in a webinar last week. “The easy spots have been taken. Now it’s harder, and we have to proactively plan for how to get out of that situation.”
It has been nearly a decade since significant regional-grid expansion projects in the Midwest, Texas and California helped expand capacity for far-off renewable energy projects. Since then, the number of clean power projects being proposed and built has skyrocketed, but transmission deployments have shrunk in terms of total deployed capacity and the scope of the projects being built. A recent report from the U.S. Department of Energy found that average transmission deployment has declined from 2,000 miles per year between 2012 and 2016 to just 700 miles per year from 2017 to 2021.
This has happened even as total utility investments in transmission have risen steadily over the past decade, according to data from the Edison Electric Institute utility trade group. This chart highlights those investment trends across the seven federally regulated regional transmission operators (RTOs) and independent system operators (ISOs) that manage transmission networks providing electricity to about two-thirds of the U.S. population, as well as other transmission entities.
But instead of going to larger-scale regional projects, the vast majority of that investment has been to upgrade existing transmission or to build smaller-scale projects to meet shorter-term reliability needs, according to the Brattle Group.
Smaller, more limited projects are easier to build because they require less consensus between regional grid operators, utilities, state regulators and other stakeholders. Often, individual utilities can build entire projects within their own territories and pass the costs on to their customers. Smaller-scale projects can also avoid triggering provisions of existing FERC orders, such as 2011’s Order 1000, that require projects to be subject to competitive bidding and increased oversight.
But this “piecemeal planning” approach, as Clements described it in Thursday’s meeting, isn’t keeping up with future needs, according to a growing body of research. Much of the solar and wind power being planned today is in remote areas, far from the cities that need the electricity it will generate.
Expanded transmission could also yield more cost-effective and reliable electricity supplies, as illustrated in the following map from another 2021 report from the Brattle Group. Sharing power across regions allows renewable resources to be transferred from regions where they are most plentiful to other regions where they can replace higher-cost electricity. Regional power sharing also reduces the risk of weather events curtailing wind and solar supplies or driving spikes in demand for heating or cooling in one particular region.
These kinds of benefits aren’t captured in planning processes that only look a few years into the future, however, said Jeff Dennis, managing director and general counsel for the Advanced Energy Economy trade group.
Navigating a complex set of federal, state and utility conflicts
This view isn’t universally shared. James Danly, the sole FERC commissioner to vote against the NOPR on Thursday, complained in his dissent that the regulations it proposes are “designed to encourage the buildout of transmission specifically to encourage the development of certain types of resources,” namely clean energy, and that they would do so “by socializing costs” on states and utilities that haven’t set their own clean energy policies.
But Clements disputed that characterization of the NOPR. “This is not a plan to foist one state’s preferences onto another,” she said. “It is also not a policy action to advance renewable energy.” Instead, it’s an effort to forestall the risk that sticking with existing planning principles will yield a less reliable and more costly grid in the decades to come, she said.
Given these risks, “the correct question is not whether long-term planning will cost customers money,” she said, but rather “whether customers get the most bang for their buck from a cost and reliability perspective.”
FERC Commissioner Mark Christie, a former Virginia utility regulator who’s expressed concerns about the potential cost burdens that regional transmission could place on states and utilities, stated that the NOPR would not alter long-standing approaches to planning and allocating costs for reliability and economic transmission projects that “keep the lights on,” as he put it.
Nor would it force grid operators or state regulators and utilities planning regional projects to conform to a prescriptive set of requirements for how long-term benefits and costs are calculated, he said. Rather, it sets out a process for those entities to identify and measure those benefits: “It requires a process; it does not require outcomes.”
The NOPR’s plan to put “states formally at the heart of the planning for these types of projects” should also work to reduce conflicts, Christie said. “It promotes just and reasonable rates; it doesn’t undercut just and reasonable rates,” he said, citing FERC’s standard under the Federal Power Act for making major policy changes.
State regulators need to play an active role to ensure “a balanced approach to building out the grid in a cost-conscious way,” John Di Stasio, president of the Large Public Power Council, a group representing municipal utilities, said in an email. As for the long-term benefits the NOPR would require regional transmission plans to consider, “there is value, but we must also be mindful of the cost to consumers,” he said.
In a press conference after Thursday’s meeting, Glick said that active state involvement could help forestall state conflicts like those that have arisen in Missouri, where state lawmakers are seeking to pass a law that would threaten the viability of the Grain Belt Express, a massive proposed transmission project that would deliver power from Kansas across Missouri to the Illinois-Indiana border.
The NOPR is “aimed at bringing the states together and hopefully developing their own approach to cost allocation,” Glick said. For example, “it might determine that State A and State C should pay for that line, not State B.”
FERC has also taken up the controversial issue of “right of first refusal,” a policy structure that can allow certain project developers to take precedence over others in transmission planning. The NOPR proposes allowing incumbent transmission utilities to receive federal first rights of refusal for projects they jointly develop with other transmission owners, which would allow such projects to avoid being subject to competitive bids.
That’s a change to standing policy in FERC Order 1000, which requires states to allow independent transmission developers to bid against utilities for regional projects. That policy has made many utilities hostile to regional transmission development, and has led some state regulators to complain that the requirement has stymied buildout of the transmission grid as a result. Several states have passed laws that counter Order 1000 by giving in-state utilities the right of first refusal over independent transmission developers, leading to legal challenges.
In an October filing, the Edison Electric Institute asked FERC to revise Order 1000’s right-of-first-refusal rules, saying they’ve “resulted in a near standstill in transmission development for regional projects and a substantial increase in process-related costs.” But a group of regulators, attorneys general and ratepayer advocates from eight states and the District of Columbia countered that argument in a November filing with FERC, stating that “competition in transmission development provides demonstrable, critical protections and benefits for ratepayers.”
Glick described the NOPR’s proposed change on right of first refusal as a compromise that could reduce these kinds of conflicts. But Paul Cicio, chair of the Electric Transmission Competition Coalition, a trade group of independent transmission developers, said in a Thursday statement that “FERC should not only hold its ground on eliminating a federal [right of first refusal], but also take steps to get rid of state-level [rights of first refusal],” which he said “have only served to protect incumbent transmission owners and their ability to charge higher rates.”
What does a long-range regional transmission plan look like?
Given all these complex conflicts, there’s good reason why regional transmission plans have been hard to push forward, said Sam Gomberg, transmission policy manager with the Union of Concerned Scientists’ climate and energy program. At the same time, “you should be able to get a broad, diverse set of stakeholders in the room to acknowledge the long list of benefits that transmission provides: greater reliability, cheaper energy, better access to resources,” he said.
That’s why Gomberg and many other clean-energy backers have been participating in the ongoing Long-Range Transmission Planning process at the Midcontinent Independent System Operator (MISO), the Midwestern grid operator whose territory stretches from Canada to the Gulf of Mexico.
MISO’s long-range planning is based on the premise that the shift from coal and natural gas to wind and solar underway in its region has created “real issues with the transmission system being able to accommodate it,” Gomberg said. Building consensus between states, utilities, independent transmission and clean-energy developers, consumer advocates, and environmental groups on how to solve that problem has required years of debate, he said.
But that work has yielded agreement on a first-round portfolio of transmission projects that could support 53 gigawatts of clean energy development, according to the nonprofit Clean Grid Alliance. It’s also expected to provide $37 billion in “financially quantifiable benefits” over 20 years for a capital investment of $10.4 billion, according to a MISO presentation last month.
MISO arrives at those figures by adding up a long list of benefits it expects the new transmission to deliver over the coming decades. Those include traditional economic measures such as reduced congestion losses and savings on fuel burned to generate power, as well as avoided investment in grid and power plant infrastructure that would otherwise be needed to make the grid more reliable.
But it also includes benefits that have rarely played a part in transmission planning processes before, Gomberg said — many of them similar to the benefits FERC is now proposing to be considered for all long-term regional transmission projects. In MISO’s case, those include its valuation of an expanded transmission system to reduce risk of forced power outages amid extreme weather events, as well as valuation of the carbon-emission reductions it’s expected to enable by allowing solar and wind power to grow faster than would be possible without it.
The result is a “stack” of benefits that go well beyond those traditionally considered, as the chart below indicates.
MISO spokesperson Brandon Morris said in an email that this “multi-value approach offers more cost-effective investments to meet regional needs and better captures the full range of benefits that will be realized by the entire subregion,” compared to incremental planning that’s “too limited in scope.”
Not all MISO stakeholders have played a constructive role in this long-range plan, Gomberg said. Canary Media has covered the problematic approach of Entergy, the utility that serves MISO’s southern territory, when it comes to engaging in long-term transmission planning. But for the most part, the process has yielded a plan for transmission projects that most of MISO can get behind, he said.
“Nobody agrees they’re perfect, but everyone agrees they’re far better than what they were,” he said. “There’s always going to be some ambiguity about estimating future benefits. You can’t let that ambiguity be a hard stop on the process.”
That’s the same collaborative process MISO used to create its last major regional transmission buildout through its Multi-Value Projects (MVP) process, which ran from 2007 to 2011. That plan led to 17 transmission projects, worth a total of about $5.2 billion, that expanded the region’s wind power transmission capacity by about 25 gigawatts.
“What MISO MVP did well — and what MISO’s most recent process is doing well — is capturing the needs of states upfront,” said Dennis of Advanced Energy Economy. “States see they need transmission to meet their reliability goals, to reduce costs for consumers, to meet their own clean energy goals, and for utilities to meet their own carbon-reduction goals.”
That led to states and utilities saying, “we’re willing to pay our share of the costs of a portfolio that provides our share of benefits,” he said — and that, in turn, resulted in “portfolios that created net benefits for everyone.”
Dennis highlighted that the current national backlog of clean energy projects unable to interconnect to the grid is due to a lack of this kind of forward-thinking planning over the past decade or so. If FERC’s new NOPR can lead to these kinds of processes being replicated across the nation,” that would go a long way toward ensuring we don’t end up in this backlog situation again.”