As the CEO of a dynamic line ratings (DLR) company, I may be one of the few people in the industry who’s actually glad major DLR regulations haven’t passed yet.
Advanced transmission technologies (ATTs), like DLR and advanced conductors, are gaining momentum in the U.S. as utilities are under growing pressure to reduce congestion, lower power bills, and connect new generation faster. Recent reporting suggests a broader federal push for ATTs may even be underway.
“Most existing regulatory thinking, such as FERC Order 1920, treats ATTs as tools to defer transmission investments and build less grid. This is fundamentally misguided in the case of DLR.”
The challenge facing utilities today isn't whether they should build more transmission. They should. The U.S. needs massive grid expansion to support load growth, electrification, reshoring, and AI data centers.
The real question is how to keep electricity affordable while building that grid.
That is where much of the current discussion around DLR goes wrong. DLR is often treated as a tool to defer transmission investments or avoid building new infrastructure. In reality, DLR cannot replace transmission expansion because its additional capacity is inherently weather-dependent.
Its greatest value lies elsewhere: reducing congestion costs and improving affordability while utilities build the grid the country still needs. Before regulators and utilities can realize those benefits, they first have to update their understanding from the hardware-centered DLR approaches of the last decade to today’s software-only model.
FERC Order 881 was an important regulatory milestone because it normalized weather-aware transmission operations through ambient adjusted ratings (AAR).
The rule recognized that transmission capacity changes with weather conditions and that static assumptions are no longer sufficient for modern grid operations. More importantly, it required ISOs and RTOs to become capable of using hourly transmission ratings in operational planning.
That groundwork was critical.
Today, PJM and ERCOT are already capable of using hourly ratings in day-ahead operational planning. SPP and ISO-NE will soon join them, and CAISO and MISO are moving to comply within the next two years.
But after FERC 881, most regulatory discussions around DLR still assume an outdated version of the technology: extensive hardware deployments of sensors mounted on select lines.
That assumption has shaped how regulators think about feasibility and scale.
For example, FERC’s 2024 DLR Advance Notice of Proposed Rulemaking (ANOPR) would have required deployment on a small fraction of the network – adding one line out of four hundred a year. The reasoning for this approach explicitly cites the high cost of DLR sensor technology. This approach would slow down, not accelerate, DLR roll-out. In contrast, software-only DLR is already covering full networks in other parts of the world without an explicit regulatory requirement.
The industry has been trying to scale DLR for years using a technology model that simply was not capable of scaling economically or operationally.
Real time measurements matter, but they’re not where most of DLR’s value is created. The real value comes from forecasting transmission capacity hours to days in advance for energy markets. Grid operators need to know how much electricity a line can safely carry in the day-ahead market and operational schedules.
Historically, accurate forecasting has been extremely difficult.
The hardest part of DLR is wind prediction because wind conditions vary dramatically from span to span depending on terrain and vegetation. Sensor-based DLR systems attempted to solve this problem by using physical measurements to calibrate weather forecasts, but the forecasts themselves remained weak.
The legacy approach was expensive, difficult to scale, and hard to justify across large networks. And that’s why DLR adoption stalled for years.
Today, advances in machine learning, hyper-local weather forecasting, terrain-aware modeling, satellite imagery, and high-resolution LiDAR data allow for the prediction of wind conditions across full networks with a level of accuracy that was previously impossible.
This shift fundamentally changes scalability, deployment timelines, and economics of DLR.
Now, sensorless DLR is practical and scalable across entire transmission systems.
The real reason DLR matters more than ever is because congestion costs are exploding.
In PJM, for example, congestion costs rose from approximately $1.8 billion in 2024 to more than $3 billion in 2025, and current trends suggest that they may double in 2026. Those costs ultimately show up in electricity bills for households and businesses.
At the same time, utilities are entering difficult conversations with regulators and public utility commissions about how to finance massive new transmission investments needed for load growth.
DLR will not eliminate the need for new infrastructure. But by reducing congestion and allowing more low-cost generation to reach demand centers, software-only DLR can help lower electricity costs in the near term while larger infrastructure projects move forward.
And it can only happen if the current reality of DLR technology is reflected in today’s regulatory conversations. Future regulations should prioritize network-wide coverage, congestion reduction, deployment speed, and affordability impact. The goal should be both maximizing the grid we already have and building the grid we still need.
The industry avoided regulating DLR too early. Now that the technology is ready to make a real impact at scale, regulators have a chance to get the next phase right.
Georg Rute is the founder and CEO of Gridraven. He previously led digitalization at Elering, Estonia's national grid, and co-founded Sympower, where he served as CTO — the company now manages 1.5GW of grid flexibility. He also helped build a Europe-wide energy data platform and holds a Master's in Sustainable Energy from Imperial College London.
