How to move more power with the transmission lines we already have

Canary Media’s Down to the Wire column tackles the more complicated challenges of decarbonizing our energy systems. Canary thanks CPower for its support of the column.

Over the past few months, we’ve been covering how the U.S. transmission grid isn’t expanding and modernizing fast enough to support the enormous growth of clean energy needed to decarbonize our electricity. We’ve also been covering how regulators, utilities and energy industry players are trying to surmount the technical, legal and economic barriers to building out a 21^st-century grid.

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.

Interconnecting wind farms: An early use case for DLR 

“When you think about operationalizing DLR, there are a couple of ways to do it,” Houghtaling said. ​“If you want to jump right in and get it running in a matter of months, you can do it manually,” deploying DLR sensors on a single power line and operating the system that manages those sensors alongside an existing grid-operations platform.

This kind of fast-and-simple deployment can help solve discrete problems for transmission operators, Houghtaling said. He cited the example of an unnamed utility customer that has deployed LineVision on a power line connecting a wind farm to its wider transmission network and has been able to significantly reduce how often the wind farm needs to reduce its output because the transmission line can’t handle the power. These forced reductions, known as curtailments, are ​“really costing ratepayers money because they can’t get the least-cost generation,” he said.

Measurements from DLR technologies could also help reduce waiting times and upgrade costs for interconnecting the hundreds of gigawatts’ worth of clean energy projects languishing in backlogged grid interconnection queues, said Adam Stern, manager of regulatory affairs for developer Enel Green Power North America.

Today, dynamic line ratings ​“are generally not allowed to be considered solutions” for the grid shortcomings that have been preventing many projects from moving forward, he said. But a small yet growing number of U.S. utilities are working on ways to use DLR to solve these kinds of clean-energy interconnection constraints. One of the furthest ahead is National Grid, the U.K.-based company that operates transmission and distribution utilities in New York and New England.

Over the past several years, National Grid has been piloting DLR systems from Ampacimon, LineVision and Lindsey on transmission lines across its Northeast U.S. service territory. This chart from National Grid indicates just how much more carrying capacity can be revealed through the use of DLR, shown in blue, than with more static ratings, shown in orange and red. 

Since then, National Grid has decided to deploy these technologies more widely, said Terron Hill, the utility’s director of clean energy development. ​“We see them as an integral part of our transmission network and how we can design our networks for future-proofing,” preparing for the major increase in clean energy demanded by state-level clean energy goals in the region.

The most immediate benefit comes from making more of the transmission network that National Grid already has, Hill said. DLR technologies can be deployed in about six months, compared to the seven to 10 years it can take to build a new transmission line (if a line can be built at all, given the public opposition to many new transmission projects).

DLR is also a perfect match for the wind farms that are expected to make up a significant portion of the renewable energy mix in the Northeast U.S., he said. Not only do high wind speeds generate power, but they also reduce the risk of overheating on power lines, sometimes quite dramatically, as indicated by this chart from a DLR review by consultancy Americans for a Clean Energy Grid.

“When the wind is blowing and those turbines are turning, that wind is having a cooling effect on those transmission lines — and that cooling effect means you can carry more power over those transmission lines,” Hill said.

Laying the groundwork for integrating DLR into U.S. grid operations 

While U.S. grid operators aren’t required to use dynamic line ratings, FERC approved an order late last year that requires transmission-owning utilities to start using something marginally better than static line ratings: ​“ambient-adjusted ratings,” or AARs. These line ratings change from season to season to account for differences in average temperature, another major factor in determining how much power a transmission line can carry.

A number of stakeholders had hoped that FERC might include DLR requirements in the same order. FERC didn’t do that, but its order did acknowledge that DLR technologies could offer ​“incremental benefits” compared to AAR alone. The order also required the country’s grid operators to ​“establish and maintain systems and procedures necessary to allow transmission owners that would like to use dynamic line ratings the ability to do so,” including revamping their systems to accept line-rating data that changes on an hourly basis.

For DLR boosters, that’s at least a good start. ​“It’s going to force utilities, [independent system operators and regional transmission organizations] to actually take that step with the data,” Ampacimon’s Alexander said, meaning they’ll have to engage with shifting real-world conditions, at least to some degree. ​“Even though they’re not required to install hardware — it’s a sensorless type of rating — they’re still going to have to go through the process of operating [using] hourly ratings, which is something they haven’t done before.”

In this sense, FERC’s AAR order is pushing grid operators and transmission-operating utilities to engage in the same kind of data acquisition and analytics and grid-control platform integration that will eventually be required if DLR ratings are to be used in ways that extend beyond single power lines. That kind of systemwide integration will become critical as transmission operators seek to make use of the expanded transmission capacity revealed by employing DLR across an entire transmission network.

That process is complicated enough for an individual transmission utility to handle, said Hill of National Grid. ​“You’re talking about cybersecurity, controls automation, telecoms,” and other key integration issues, all of which must be approved by regulators before they can be implemented beyond pilot scale, he said.

It gets even more complicated when multiple utilities have to coordinate their activities. Alexander pointed out that European transmission system operators like Belgium’s Elia have a simpler time with this undertaking because they simultaneously own the transmission network and manage the energy market structures that determine how power flows across it. In the U.S., by contrast, the FERC-regulated transmission organizations that manage these energy market functions don’t own the power lines themselves — utilities do.

The disconnect between grid operators and transmission-owning and -operating utilities complicates how U.S. grids can implement DLR on a wide scale, said Charles Cates, manager of operations engineering analysis for Southwest Power Pool (SPP), the transmission operator serving parts of 14 states from north Texas to North Dakota. SPP and its transmission-owning member utilities are now busy implementing FERC’s AAR order, he said.

AAR and DLR both use data on ambient temperature and solar radiation to calculate how much power lines can handle, though DLR collects that data much more frequently. The big difference between the two is that DLR also incorporates wind-speed data. ​“Wind speed has the most impact on lines, but it’s also the most volatile,” Cates said. ​“It can change minute by minute, and it’s really hard to predict.”

That injects a certain amount of uncertainty into any DLR-derived equation of how much extra power any particular line can carry, he said. ​“We have to make sure we don’t go beyond what our ratings can handle,” Cates said. ​“We don’t want lines sagging to the ground.” And because every individual transmission-owning utility is ultimately responsible for maintaining the safe operations of its own grid, it’s not the kind of thing a grid operator like SPP can just order every utility to implement in the same fashion, he said.

Ampacimon’s Alexander conceded that the unpredictability of wind speed does require grid operators using DLR to consider real-time variability in their hour-ahead forecasts of how much power any one line can handle. ​“One of the ways you mitigate that risk is by monitoring the system in real time, and if you do ever exceed that real-time rating, the system gives you an alarm” to reduce power flows, he said.

But that same real-time visibility can also help grid operators avoid emergencies caused by overloading lines. In rare but significant cases, DLR technologies reveal that lines actually have less capacity than their static ratings indicate, as shown in the following illustration from Americans for a Clean Energy Grid. That’s a critical piece of information for grid operators whose first responsibility is to maintain a reliable system.

Jay Caspary, a vice president at Grid Strategies and SPP’s former engineering director and head of transmission development, wrote in a 2020 article that data like this shows that today’s static line ratings, and even updated ambient-adjusted ratings, could put transmission grids at risk. ​“The industry needs to focus on better approaches to manage risk and improve rating accuracy, not just increasing ratings,” he wrote.

How U.S. utilities and grid operators are putting DLR into action

While utilities in the Southwest Power Pool are largely focused on adopting AARs, some of the utilities in the territory of PJM, the grid operator that manages a transmission network stretching from Chicago to the mid-Atlantic coast, are moving ahead with DLR.

In March, PJM announced that it and its stakeholder utilities were ​“working to finalize the systems and procedures necessary to permit the acceptance of dynamic line rating” data from utilities to PJM’s transmission system operators, including the vital ​“at least hourly” updates on how much power lines can carry — a big change from the static ratings used to determine how much power can flow across its 13-state network.

That change has been driven largely by the decision by a handful of utilities within PJM’s territory to implement DLRs on a set of transmission lines, Alexander said. Those include PPL, the utility serving much of eastern and central Pennsylvania, and Duquesne Light Co., which serves two western Pennsylvania counties centered around Pittsburgh.

PPL installed DLR systems from Ampacimon on two transmission lines that had been cited by PJM as causing significant congestion for the region they served, he said. Over the course of 2020 and 2021, the two companies were able to use the data coming from the DLR systems to ​“clear” the congestion from those lines, according to Alexander.

Duquesne Light installed LineVision DLR systems on one of its transmission lines last year and two this year, and the utility has been working for the past six months on ​“operationalizing the data” that comes from them, said Liz Cook, the utility’s general manager of advanced grid solutions.

Over her two decades working as a power systems engineer and analyst, Cook has long questioned the utility industry’s reliance on static line ratings. ​“We’re running such a dynamic system, and our largest assets are using static assumptions,” she said.

DOE’s 2019 report to Congress made a similar point: ​“The electric power system is becoming more dynamic with a need to make faster operational decisions based on more rapidly changing conditions. Real-time monitoring of the grid can support this need, especially as the mix of generation sources serving the country changes,” with wind and solar power growing and coal and nuclear power plants closing down.

Duquesne Light has had to plan ahead for investing in transmission upgrades to cope with the threat of losing coal and nuclear plants owned by neighboring utilities, Cook pointed out. It’s also trying to deploy technology that can prepare it for the uncertain mix of power resources it will be managing for decades to come, she said.

When it comes to deploying DLR technology, ​“right now, there’s a ​‘Can we trust it?’ phenomenon,” Cook said. ​“What if operators knew there was additional capacity? Could they, in the short term, operate to get through gaps? Just having that awareness can give you more flexibility.”

LineVision’s Houghtaling noted that not all stakeholders in PJM territory can be expected to be supportive of deploying DLR in ways that reduce grid constraints. ​“The generator stakeholders are OK with us proceeding the way we are and selling us more expensive electricity when we have congestion,” he said. ​“They don’t mind that at all.”

Other transmission-owning utilities might prefer to build new transmission lines or replace existing lines with cables that can carry more power since those expenses can be passed on to customers and earn the utility a guaranteed rate of return. Some U.S. utilities that have piloted DLR technologies have declined to move ahead with broader deployments because they don’t want to miss out on the opportunity to make money investing in new transmission, he said.

But utilities are being forced to acknowledge that they are running up against the hard limits of building new transmission, Houghtaling said. Constructing big new transmission lines is difficult and time-consuming even before you consider the intense public opposition to many such projects. At the same time, demand for power is soaring thanks to electrification and other trends.

“The amount of capacity utilities need to deliver — for electric-vehicle charging, for data centers — there’s just no chance they’ll be able to build transmission at the pace needed to deliver all this load growth and [to adapt to] the changing load patterns,” Houghtaling said. ​“Not only can you not build transmission that fast — you may not be able to build it at all.”

The U.S. must dramatically expand its transmission grid capacity to manage the massive clean energy growth needed to reduce carbon emissions fast enough to hit the climate change goals set by the Biden administration and a growing number of states. Building new transmission will be vital to achieving this goal, WATT Coalition’s Gramlich said — but DLR and other technologies have to be part of the solution as well.

“It may be easier to continue operating the transmission grid as if its capacity and topology is static and immutable,” Gramlich said after a FERC workshop last year on grid-enhancing technologies. ​“But to continue as we have been for 140 years is to leave consumers paying billions of dollars for congestion every year and leave interconnection queues to balloon with renewable energy projects facing massive upgrade costs.”

DLR technologies are only one part of the solution. In our next installment of Down to the Wire, we’ll delve into another class of GETs that can help expand the capacity of the existing grid, sometimes without deploying any hardware at all: topology optimization software and other advanced software that can tap into today’s massive computing power to discover ways to reconfigure transmission networks to unblock power flow bottlenecks and open up access to clean energy.