Of the many challenges confronting the nation’s aging, straining electric grid, the need for a lot of new transmission capacity is among the most pressing, experts and policymakers say.
Earlier this year, the U.S. Department of Energy said the nation will need thousands of miles of new lines to better link regions to handle extreme weather, reduce costs and connect new renewable energy projects.
But building a new interregional transmission line can take a decade or more — chiefly because of siting and permitting delays, local resistance, planning problems, cost allocation and other obstacles.
And while Congress has taken some steps on permitting reform (in this summer’s debt limit deal), there’s a suite of technologies that proponents and some state and federal regulators agree could get more out of the existing transmission system right now and potentially reduce the need for new wires.
They’re called “grid-enhancing technologies,” or GETs in industry shorthand, and in many cases they’ve been embraced elsewhere but have been slower to take root in the United States.
“If we don’t squeeze every drop out of the existing system it’s going to be a tough sell as we consider the costs involved in transmission expansion,” said Dan Scripps, chair of Michigan’s utility commission, at a Federal Energy Regulatory Commission task force meeting last month. “And I believe that grid-enhancing technologies can help us do that to maximize the value from the infrastructure that we have today.”
What are GETs?
Grid-enhancing technologies include a variety of tools to maximize the ability of the grid to handle the flow of electricity. They include sensors, power-flow devices, software and hardware that can better deliver real-time weather data and other technologies like topology optimization, which can identify the best grid configurations and route power flow around bottlenecks. Think of the electric grid as a road system and grid-enhancing technologies as traffic control devices and variable speed limits that can help alleviate congestion, a Department of Energy paper says.
And congestion on the nation’s electric grid is a real problem. Defined broadly, congestion in electric terms means any time physical constraints on the power system prevent the cheapest power from flowing to customers, which, naturally, raises costs.
“For example, the flow of power may be restricted by the maximum thermal limit of a transformer or power line conductor,” the Department of Energy says. “Therefore, operators are forced to reroute power through less optimal paths and rely on more expensive power generation, like conventional fossil fuels, while curtailing renewable wind or solar to safely meet the demand of their customers.”
A report released in July by Grid Strategies, a consulting firm that works to integrate renewable power into the electric grid, found that congestion costs (after doubling between 2020 and 2021) rose to $12.1 billion in 2022, an increase of 56% from 2021, in regions of the country controlled by six large regional transmission organizations. By extrapolating that increase to the rest of the U.S., the firm estimated that the total cost to electric customers of congestion in 2022 was nearly $21 billion.
“The best way to reduce transmission congestion is to increase transmission capacity. However, very little of transmission spending is on new large-scale, high-voltage transmission lines,” Grid Strategies wrote. “In addition, few U.S. utilities have adopted dynamic line ratings, advanced power flow control or topology optimization (together known as Grid Enhancing Technologies or GETs) to make more efficient use of existing grid infrastructure.”
Why adoption of
GETs has lagged
There was broad consensus at the seventh meeting last month of FERC’s Joint Federal-State Task Force on Electric Transmission that GETs could yield big cost and reliability benefits for grid operators and electric customers.
“Perhaps the most compelling case to me for these technologies is that right now they can reduce grid congestion allowing our markets to consistently access lower cost power and to respond to real time reliability issues. And that’s particularly important when we’re dealing with extreme weather events,” said Andrew French, a member of the Kansas Corporation Commission who serves on the task force.
So why aren’t these types of technologies more
prevalent in the
United States?
The biggest reason, grid experts say, is how utilities earn money for grid upgrades and how their performance is measured.
“Utilities are not necessarily directly economically impacted by the inefficient use of transmission infrastructure,” said Darcie Houck, a California utilities commissioner who also serves on the task force, adding that often utilities pass on congestion costs to power generators and customers. “Utilities are financially motivated to build more capital-intensive transmission projects to grow their rate base which they earn a return on… GETs may defer or negate the need for such capital projects thereby reducing utility revenues.”
Part of the reluctance also stems from a need for grid operators to “validate the technologies on their own system because there are not references publicly available on performance, integration, and deployment,” the Idaho National Laboratory wrote in a report last year.
Also creating hesitance is a lack of industry standards and specifications for some of the technologies, as well as potential security concerns, said Andrew Phillips, vice president of transmission and distribution at the Electric Power Research Institute, during the FERC task force meeting.
“When a new technology comes to market, we need a spec to buy to. We need to be confident it’s going to last 30 or 40 years. And that’s a really important thing and often a barrier,” Phillips said, adding that EPRI, a research and development nonprofit, has developed testing for some technologies like advanced conductors and is working on standards for others.
“We need an industry accepted way of evaluating these technologies, incorporating them into our plans and then exercising those plans.”
Yet, despite the past resistance, some see attitudes among utilities changing.
“Ratepayers aren’t going to pay for twice as much grid as we have today so they have to look at other solutions,” said Julia Selker, chief operating officer at Grid Strategies as well as the executive director of the WATT Coalition, which is pushing for broader adoption of GETs. “I see a mindset shift.”
A push from FERC
and the states
FERC has taken recent steps to get more out of the existing transmission system and push for consideration of new technologies.
In 2021, FERC issued a final rule requiring transmission providers to use “ambient-adjusted ratings” for transmission lines that take into account actual air temperature and other weather conditions, instead of limiting a line’s capacity based on conservative, worst-case assumptions.
The order also opened the door for transmission owners to explore “dynamic line ratings,” a more real-time rating that can account for other factors that might increase line capacity, like wind speed, cloud cover and other conditions.
This summer, PPL Electric, which has about 1.4 million customers in eastern and central Pennsylvania, won an industry award for being the first American electric company to install and integrate a dynamic line rating system within its transmission management and market operations. The technology will save its customers’ an estimated $23 million per year in congestion costs, the company says. A 2021 report commissioned by the WATT Coalition contends that deploying GETs nationwide would save more $5 billion a year in energy costs, against an upfront investment of $2.7 billion in the first year.
In July, as part of its effort to help clear backlogs of new power projects seeking to connect to the grid, FERC also required transmission providers to consider grid-enhancing technologies in their interconnection studies. And another proposed rule could also require their consideration in transmission planning.
“GETs belong in long-term planning,” Selker said. “If you’re not considering GETs than you’re not making the most efficient decisions for customers.”
But there’s been some reluctance among FERC commissioners to mandate any specific technology.
“We need to really listen to the engineers on this,” Commissioner Mark Christie, a former Virginia utility regulator, said. “There’s tremendous benefit if you get it right. There’s not benefit if you don’t.”
In a concurrence filed on the new interconnection rule, Christie acknowledged the vested interest of transmission owners in building “costly new transmission assets” instead of potentially less expensive technologies that could get more out of existing lines. But he also said there was “plenty of rent seeking” as well by companies who sell grid-enhancing technologies and the organizations they fund who stand to profit from any regulation mandating their use.
“Striking the appropriate balance — one that is in the public interest — is a challenge,” Christie said.
But there’s also a role for states. Selker said utility regulators in several states, including Michigan, Nevada and North Carolina, have asked their companies to report on their pursuit of federal funding for grid upgrades. There’s about $14 billion in federal funding available to states, tribes and utilities over the next several years for grid-enhancing technologies and other upgrades.
Caitlin Marquis, a managing director at Advanced Energy United, a trade group for clean energy companies, called the FERC requirement that GETs be considered in interconnection a small first step.
“There is a requirement to evaluate these technologies, there is a reporting requirement, but there is a lot left to transmission providers’ discretion… It’s to be seen whether it results in increased use of GETs,” she said. “GETs is definitely an area where there is state interest and states could definitely be playing a bigger role in ensuring they get considered.”
Several state regulators on the FERC task force took a similar view.
“We need to squeeze every bit of value out of our existing system for the benefit of our ratepayers,” said Kimberly Duffley, a North Carolina utilities commissioner. “One thing state commissions can do is evaluate their existing rules to ensure they’re creating conditions for GETs to be considered where appropriate.”
Marissa Gillett, chair of the Connecticut Public Utilities Regulatory Authority, said it’s up to state and federal regulators to develop shared savings and other programs to push utilities to consider “non-wires” grid solutions, combining “a healthy disincentive with potential incentives.”
“Our ratepayers need us as regulators, whether state or federal level, to define the rules of the road and to insist on a fuller accounting of how an incumbent [utility] lands on a capital intensive solution,” she said. “I do think we need to go beyond the simple instructions that GETs should be considered.”
She noted that utility decisions on what to build aren’t made just on engineering merits in a vacuum.
“We should all trust but verify but also encourage and enforce if necessary,” she said.
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