FERC Order 1920, issued in final form in May 2024 and now nearly two years into its compliance arc, is usually described as the long-term regional transmission planning rule. The framing is accurate but underweights what happened to grid-enhancing technologies inside the order. GETs were referenced. They were not required as standalone solutions. The order instructed transmission providers to evaluate them alongside conventional alternatives in regional planning, and to file tariff revisions describing how that evaluation would work. The compliance filings RTOs submitted in early 2025, plus the supplemental filings several of them filed late last year, are the place to read what that evaluation actually looks like in practice.
What changed in 2026 is not the regulatory text. The text is the same. What changed is that the IRPs and capacity expansion plans utilities are now writing for the 2027 to 2029 window, the same window driving the gas turbine procurement problem covered in earlier posts in this series, have started leaning on GETs as a delivery mechanism for incremental transfer capability. The order told planners to consider GETs. The planning shops downstream are now depending on them.
What GETs actually are
The acronym covers four technology categories. The categories overlap and the vendors selling them often span more than one.
Dynamic line ratings are the largest single bucket by deployment volume. A conventional transmission line is rated on a static basis, usually a conservative summer rating that assumes 95 degree Fahrenheit ambient, low wind, and full solar load. Real conditions for most of the year are below those assumptions. A DLR system uses sensors on the line (LineVision, Heimdall Power, Ampacimon, LineVision again) or weather modeling tied to line geometry to set a real-time rating that reflects actual conditions. Typical observed gains on lines where DLR has been deployed are 10 to 30 percent of additional thermal capacity, available most hours of the year, with the largest gains on lines that face into prevailing winds.
Advanced power flow controls, mainly the Smart Wires SmartValve and a small set of competing products, install power-electronics-based devices on transmission lines that can dynamically push or pull power flow off congested paths and onto underutilized parallel paths. They do not add new wires. They use existing wires more fully. The unit economics depend on the specific congestion pattern, but on networks where parallel-path congestion is the binding constraint, the deferred capital cost from avoided reconductoring or new-build can be a multiple of the device cost.
Topology optimization is software. Tools from NewGrid, GridBright, and a handful of academic groups identify dispatchable switching actions inside the existing transmission topology that reduce congestion. The implementation cost is mostly model integration and operator workflow change, with no new hardware. The reliability authorities have moved cautiously here because automated switching changes the control room operating posture, but the savings claims from pilot studies have been large enough that several RTOs now have topology optimization on their roadmaps.
Dynamic transformer ratings are the newest category and the smallest by deployment volume. The principle is the same as DLR: use real conditions, including oil temperature and load history, to rate the transformer in real time rather than nameplate. The technology is mature for substations that already have detailed transformer monitoring. The deployment friction is the operating culture around transformer protection.
Why utilities have not deployed these faster
The standard answer is the rate-of-return-on-rate-base capital incentive. The longer answer has more pieces.
Investor-owned utilities earn a regulated return on capital invested in transmission. A new transmission line at $3 million per mile builds rate base. A DLR retrofit at perhaps $100,000 per substation site, depending on configuration, does not, or builds rate base only marginally. The accounting treatment for GETs in many jurisdictions is operating expense or short-life capital, both of which earn less to a utility than long-life capital does. The standard answer is that this misalignment is the binding constraint, and FERC Order 1920 plus the subsequent FERC Order 1977 on construction work in progress incentives were intended to start fixing it.
The fuller answer adds the operational layer. A static line rating is a number an operator can hold in their head. A dynamic line rating is a real-time data feed that has to be integrated into the energy management system, the security-constrained economic dispatch, the day-ahead unit commitment, and the operator training pipeline. Several of the RTOs that took DLR pilot projects to scale have published lessons learned that center on these integration costs. The hardware was the cheap part. The control room and market system integration was where the multi-year timelines came from.
The third piece is reliability culture. NERC standards on transmission planning have historically been written around static ratings because static ratings are easy to audit. NERC has issued guidance on incorporating DLR into planning and operations, but the audit-friendly default still tilts the planning posture toward conservative static numbers. Several FERC Order 1920 compliance filings included language asking NERC to clarify treatment of GETs in TPL-001 and other transmission planning standards. That work is still ongoing.
What the 2025 compliance filings actually committed to
The RTO compliance filings for FERC Order 1920 were due in early 2025. PJM, MISO, SPP, ISO-NE, NYISO, and CAISO all submitted. Most filed supplemental amendments later in 2025 in response to FERC deficiency letters.
PJM’s compliance filing established a structured evaluation process for GETs as a benefit category in long-term planning scenarios, with a list of candidate technologies and a methodology for monetizing the deferred or avoided new-build value. The supplemental filing added more specific treatment of dynamic line ratings on lines flagged by interconnection queue cluster studies as binding constraints.
MISO’s filing was structurally similar. The MISO long-range transmission planning portfolios approved in 2022 and 2024 already included some GETs scope, mainly DLR on specific lines and advanced power flow controls on identified parallel-path congestion. The Order 1920 compliance filing formalized the evaluation process going forward and added the requirement that any new-build proposal in the long-term portfolio explicitly demonstrate why a GETs alternative would not meet the need.
SPP, ISO-NE, NYISO, and CAISO filed compliance plans with the same general shape. The differences are in the specifics of the evaluation methodology, the cost-allocation treatment, and the scenarios used to test whether a GETs deployment can defer or avoid a conventional project.
ERCOT, not under FERC jurisdiction in the same way, has its own track. The Texas PUC and ERCOT have moved on GETs through the regional planning process and through specific approvals for DLR deployments tied to interconnection. The pace there has been faster on DLR specifically than on the other categories.
Where deployment is actually happening
Named deployments through early 2026, in rough order of scale.
AEP across multiple state jurisdictions has DLR deployed on a substantial portion of its 765 kV and 345 kV transmission network in the Ohio, West Virginia, and Indiana service territories. The original driver was the AEP-Indiana Michigan and AEP-Ohio data center interconnection queue, where avoiding new-build through better utilization of existing assets was specifically called out in regulatory proceedings.
Avangrid in the Northeast has deployed DLR and advanced power flow controls on its New York and New England transmission, with most of the recent capacity additions tied to the offshore wind interconnection program. The advanced power flow controls let the system shift load away from points of constraint when offshore output spikes.
Xcel in Colorado and the Upper Midwest has DLR on selected lines, with the deployment paced behind the integration into the joint dispatch agreement with SPP and MISO neighbors.
Dominion in Virginia has DLR pilots tied to the Northern Virginia data center transmission upgrades, with the explicit framing in PJM filings that GETs are reducing the megawatt count of new-build required to serve the load growth.
ENGIE North America, operating as an independent transmission developer in MISO and SPP, has used advanced power flow controls and DLR as part of competitive transmission solicitation responses. The competitive transmission process has produced more aggressive GETs scope on average than the incumbent utility planning processes have.
Smart Wires reports installed devices across multiple RTOs at a unit volume in the low thousands by early 2026, with the bulk of recent installations in PJM and CAISO. LineVision reports DLR deployments on over 10,000 line-miles globally, with US share growing.
The aggregate megawatt impact across the US is real but distributed. The single biggest claim, a roughly 5 to 8 percent incremental utilization of existing thermal transmission capacity from DLR alone if deployed across the high-priority subset of the US transmission system, has been published by multiple grid research groups. That percentage applied to the binding-constraint portions of the network is a multi-gigawatt number. It is not, however, an evenly distributed number, and the locations where the incremental capacity shows up are not always the locations where the load growth or queue congestion is concentrated.
What this means for the 2027 to 2029 window
The earlier posts in this series identified the 2027 to 2029 gas turbine gap, the storage build-out as lever 1, coal life-extension as lever 2, and demand-side reliability as lever 3. GETs do not fit neatly into the lever framing because they do not change the generation stack. What they change is the deliverability of the generation stack that already exists or is already in interconnection queue.
The IRP analysts now treating GETs as a delivery mechanism are doing so because the conventional transmission planning timelines do not close the gap. A new 345 kV line takes 7 to 10 years from need identification to in-service. A reconductoring project on an existing right of way takes 3 to 5 years. A DLR retrofit takes 12 to 18 months. An advanced power flow controls deployment takes 18 to 30 months. The reliability planners who have to balance their books in 2027 are reaching for the tools that can produce megawatts on the operational side of the 2027 to 2029 window. That is GETs.
The risk in the framing is that GETs are not free megawatts. They are incremental megawatts that require operational integration, control room cultural change, and a market-system treatment that most RTOs are still working through. The IRPs leaning hardest on them are leaning past where the deployment infrastructure currently is, on the bet that the deployment ramp will catch up to the assumption. Whether that bet pays in time for the reliability window is the question the next several years of FERC Order 1920 compliance work is implicitly trying to answer.