Grid-enhancing technologies enable us to get more out of existing power lines. Here’s an in-depth look at one such technology: dynamic line rating.
But in the meantime — and given how long it takes to build new transmission lines, that meantime could be a long time indeed — there are ways to expand the clean-energy capacity of the power grids we already have. One of the most effective methods for doing this could be using grid-enhancing technologies, or GETs for short.
The term GETs covers a variety of technologies, each with its own role to play. Dynamic line-rating systems can reveal that high-voltage power lines are able to safely carry more electricity than previously known. Topology optimization software can discover ways to configure transmission grid networks to ease power flow bottlenecks that are preventing power from reaching customers. Power flow routing devices can actively direct the flow of electrons from overloaded to underutilized power lines in real time.
Real-world deployments of these GETs over the past decade have shown that they can cost-effectively deliver benefits like redirecting power flows around congested grid lines and reducing the cost of interconnecting more solar and wind power resources. More recent studies have shown that using multiple types of GETs in tandem can unlock enormous amounts of latent capacity on U.S. transmission grids.
A study last year indicated that the use of GETs on the grids crisscrossing the wind-rich plains of Oklahoma and Kansas could double the capacity for new clean energy projects and reduce the amount of power lost to grid congestion, yielding paybacks twice the cost of deploying the technologies in the first year of operations alone.
And in February of this year, the U.S. Department of Energy released a study indicating GETs could pay back their costs through higher production and increased capacity for renewables in New York state within half a decade — far more quickly than traditional grid upgrades.
Achieving these hypothetical best-case scenarios from GETs deployments will take a lot of work, however. Despite their growing track record in delivering real-world value in deployments in Europe and Australia, GETs are just beginning to be put to use in active grid planning and operations in the U.S. Integrating multiple technologies across wide swaths of the grid is still in the realm of computer modeling rather than real-world grid operations.
There are a lot of reasons for this. Utilities are conservative when it comes to adopting new technologies and leery of novel approaches to operating their grids that could threaten safety and reliability.
But there’s also a more troubling barrier to deployments of GETs in the U.S., one stemming from misaligned regulatory and economic incentives. Simply put, most U.S. transmission-owning utilities make money by convincing regulators to allow them to invest in new power lines and make other capital expenditures for equipment — not by making the power lines they already have work more efficiently.
As DOE’s report notes, “transmission owners and utilities receive a rate of return on their capital investments for infrastructure projects. GETs often represent lower capital cost alternatives to traditional investments such as new transmission lines, meaning a lower overall return for investors.”
This utility regulatory paradigm is known as “cost of service” because it rewards utilities with guaranteed rates of return for costs incurred by building new capital infrastructure and equipment — and many energy experts fear that it is fundamentally mismatched with the needs of a modernizing grid. This has stymied action on investing even in technology required by federal law. The 2005 Energy Policy Act directs the Federal Energy Regulatory Commission to develop incentives to improve operations of the interstate transmission networks it oversees, but FERC has yet to create incentives for deploying GETs.
Back in September, FERC fielded several proposals for how to structure GETs incentives for utilities, transmission owners and the grid operators that manage transmission planning and investment for electricity markets serving about two-thirds of the U.S. population. But “there hasn’t really been any action since that conference,” said Rob Gramlich, president of consultancy Grid Strategies and executive director of the WATT Coalition, a trade group of GETs companies. That’s frustrating, given that WATT and clean energy industry trade group Advanced Energy Economy have had a GETs incentive proposal filed with FERC since June 2020, he said.
FERC has been quite busy since then, Gramlich acknowledged. Over the past few months, the commission has unveiled a series of ambitious policy proposals stemming from a year-long effort to unblock the grid bottlenecks that are causing multibillion-dollar congestion costs and preventing solar, wind and battery projects from interconnecting to the grid.
The long-range grid-planning and interconnection proposals that have emerged from this process include a role for GETs, as FERC Commissioner Willie Phillips noted in the June meeting during which FERC approved a plan for interconnecting clean energy projects to the grid more quickly.
“GETs are something I talk about a lot,” Phillips said. “I think this is important because…it could save consumers money as we move forward and make these important investments” in the grid.
This installment of Down to the Wire will be the first in a series exploring a range of grid-enhancing technologies, as well as the regulatory complications that have stymied their uptake in the U.S. and possible approaches for getting more GETs deployed. To begin with, we’ll take a look at dynamic line-rating technologies, the GET category poised for the most rapid proliferation on U.S. grids.
Getting GETs into action
What needs to happen for GETs to move from pilot projects to playing an active role in expanding U.S. clean energy capacity? An effective incentive structure would really help, Gramlich said. That view has been echoed by U.S. senators and House members who’ve issued repeated demands for FERC to create such incentives over the past few years.
At the same time, utilities and grid operators have a lot of work ahead to integrate GETs into grid-control software systems and train their grid operators on how to use them effectively. That integration challenge is harder in the fractured U.S. utility environment, compared to Europe, Australia, China and other parts of the world that have largely centralized the control of the transmission grid among a small number of nationally regulated entities.
The U.S. power grid, by contrast, is split up into multiple regional transmission organizations and independent system operators overseen by FERC, as well as parts of the country that lack any regional entity in charge of getting transmission-owning utilities to play by the same rules. What’s more, the U.S. has thousands of utilities that are regulated at the state level. Regulations must filter down from federally regulated transmission operators to state utility regulators to individual utilities to drive significant changes.
“It’s hard to boil those down to any neat public-policy approach,” Gramlich said. Instead, the groundwork for broader adoption of GETs across the U.S. transmission system is being laid in a variety of ways — through “these FERC proceedings, and the pressure that a lot of state regulatory commissions are putting on transmission providers, and the actions of some individual utilities and grid operators,” he said.
Of the range of grid-enhancing technologies at hand, dynamic line-rating (DLR) systems are the furthest along in becoming a standard part of how utilities and grid operators manage the grid, Gramlich said. Beyond having more than a decade of operations in the field, they also offer a relatively clear-cut advantage over the way that transmission grids are operated today.
Dynamic line ratings: Finding the true carrying capacity of the transmission grid
For decades, utilities and grid operators have relied on static ratings of power-line capacity, which often dramatically underestimate how much power lines can carry. They presume relatively poor operating conditions — hot, dry, windless days that put power lines under great heat stress — so they’re inherently conservative. The static line-rating methodology tends to “produce an inflexible constraint that does not take advantage of changing or favorable environmental conditions that allow for greater transmission usage in many hours of the year,” according to a 2019 DOE report to Congress.
DLR systems, in contrast, offer real-time data on power-line capacity, reflecting the role of real-world conditions such as air temperature, rain, sun and wind speed. DLR devices can be attached directly to the transmission lines they’re monitoring, or they can use sensing equipment attached to transmission pylons that monitor lines from a distance.
That data is used to determine whether power lines can safely increase their power flows without overheating, which can cause the metal they’re made of to stretch and sag to the ground or into the surrounding vegetation, or otherwise creating unsafe operating conditions. This visibility into real-world conditions can often discover more transmission capacity than static line ratings presume, with some significant improvements to grid operations as a result.
But despite years of testing and verification of the benefits of DLR, U.S. utilities haven’t kept up with the European grid operators that have taken the lead in using them.
Belgian grid operator Elia launched Europe’s use of DLR technology more than a decade ago. That prepared the grid operator for relying on the technology in 2014 when it faced the challenge of increasing electricity capacity to make up for several nuclear power plants that needed to go offline over the winter.
Belgium was “surrounded by other countries with surpluses” of energy, explained Joey Alexander, vice president for North American operations for Belgian DLR provider Ampacimon. “The problem was they didn’t have sufficient import capacity” on Elia’s transmission connections to the Netherlands, Germany and France.
To overcome this constraint, Elia turned to Ampacimon’s then-new DLR technology, which uses sensors that attach to transmission lines to actively measure their conditions. Those sensors revealed that the power lines connecting Belgium to its neighbors were in fact capable of carrying significantly more electricity than their static ratings indicated, opening up enough import capacity to carry the country through its nuclear power shortage.
Since then, Elia has deployed the Belgian company’s DLR technology in a more systematic way to get more accurate capacity ratings for its entire network, Alexander said. Over the past five years, Elia has been able to achieve an average 30 percent increase on its transmission grid compared to its static line ratings, as this chart indicates.
Other European transmission grid operators including TenneT, RTE, Statnett and Energinet have adopted DLR technology to solve grid congestion problems, according to a 2020 report from wind power industry trade group WindEurope and a 2021 report from European GETs trade group CurrENT. “In some of these cases DLR is fully integrated in short- and long-term system planning studies,” the WindEurope report states.
U.S. utilities have been conducting their own DLR experiments over the past decade. Two early pilot projects from Texas utility Oncor and the New York Power Authority found average real-time transmission capacity to be at least 30 percent greater than static ratings, and sometimes much higher, according to an analysis by Grid Strategies.
But integrating this real-time data into everyday grid operations isn’t as simple as putting sensors on lines and turning them on, Alexander pointed out. That’s because a transmission network consists of multiple power lines and interconnection nodes that operate as a unified whole. Solving for constraints on one power line doesn’t necessarily translate to solving the constraints that influence interactions of the entire system.
“The transmission line is not the whole story,” Alexander said. “What about your substations and everything else in that path? You can’t necessarily increase it by the same amount. There are some cases where we’re looking at 50 percent additional transmission capacity or more, but they can’t use it” because of downstream constraints on another part of the system.
As the DOE’s February report put it, “DLR has the potential to expand the nation’s power highway system, but the exits and intersections must be capable of using that new capability for it to be worthwhile.”
U.S. company LineVision, which has deployed its lidar and electromagnetic sensor-based DLR technology on power lines in the U.S. and Europe, has also found that it can be challenging to roll out its technology systemwide. So far, said Alex Houghtaling, LineVision’s vice president of sales, the most promising early-stage applications are on single power lines — such as those connecting remote wind farms to the broader transmission network.