Grid-enhancing technology vendors sell to transmission owners by attaching the product to a duty the owner already carries: Order 1920 planning, Order 881 line ratings or a state GETs law. They win one paid deployment on a congested line, priced against reconductoring or a rebuild. Transmission planning sponsors the case. Operations and the rates team decide whether it scales.
Which rules make a transmission owner take the meeting?
Four rules matter, and each sits at a different stage. Sell against the ones in force.
Order 1920 is the main planning hook. The final rule (Federal Register, June 2024) requires transmission providers in each planning region to consider dynamic line ratings, advanced power flow control devices, advanced conductors and transmission switching. Planners must explain in enough detail why each was or was not built into selected regional facilities. FERC affirmed the rule in Order 1920-B (April 2025). The Fourth Circuit has heard oral argument on the appeals and had not ruled when RTO Insider reported the hearing in September 2026. Compliance work was still open in mid-2026: PJM's transmission owners asked for an extension to August 11, 2026 for their part of the regional filing (June 2026).
Order 881 requires ambient-adjusted ratings. FERC set a July 2025 deadline and then approved numerous extension requests. PJM began hourly ambient-adjusted ratings on March 4, 2026, while MISO expects full compliance at the end of 2028 (Utility Dive, March 2026). AES wrote that ambient-adjusted ratings and DLR need the same operational changes: energy management system upgrades, operator training and new rating methods (April 2024). Sell DLR into that project while it is open.
FERC's dynamic line ratings rulemaking stays open. The advance notice was published in July 2024, and FERC's August 2026 regulatory agenda lists the next action as "undetermined". No federal DLR mandate existed at that date, so do not pitch one.
State laws fill the gap. The WATT Coalition, an industry group, counted nine states that passed GETs laws in 2025 (July 2025). Utah HB 212 makes utilities analyze GETs when they propose transmission additions and lets the commission approve cost recovery when GETs are cost-effective. Indiana SB 422 puts GETs into integrated resource plans. Ohio HB 15 requires an evaluation of advanced transmission technologies in certificate applications.
Who inside a transmission owner actually buys?
Five teams touch the deal. Transmission planning owns the need and the alternatives analysis. Standards and asset management own the equipment specification. Operations owns the control room and the energy management system. Regulatory and rates own cost recovery. IT and OT security review every sensor and data feed.
The published deployments show this split. An engineer from PPL's transmission and substation standards group presented its DLR program, which PPL integrated with its own EMS and with PJM (June 2025). AES listed its vendor selection criteria: rating accuracy and track record, installation without an outage, sensors that can be moved or extended, and NERC CIP cybersecurity compliance (April 2024). Plan a separate conversation for each criterion.
For how signature authority works across utilities, see who signs the purchase at a utility, a data center and an IPP.
What does each technology need to win?
| Technology | Regulatory hook | Lead buyer team | Proof the buyer wants |
|---|---|---|---|
| Dynamic line ratings | Order 881 rating work; Order 1920 consideration; federal DLR rule still pending (August 2026) | Operations and EMS, with transmission standards | Gain over static ratings on the owner's own lines. AES measured a 61% average gain on a 345 kV line over six months (April 2024) |
| Advanced conductors and reconductoring | Order 1920 consideration; Montana HB 729 lets qualifying conductors earn an incremental return in rate base (DOE, April 2024) | Transmission planning and asset management | Cost per mile and capacity against a rebuild. Reconductoring can up to double line capacity at typically less than half the cost of new lines (UC Berkeley and GridLab, April 2024) |
| Advanced power flow control | Order 1920 consideration; Ohio HB 15 | Transmission planning | Congestion relief against a wires upgrade. A DOE study in New York found DLR and power flow control cost less than 25% of traditional upgrades (DOE, April 2024) |
| Topology optimization (transmission switching) | Order 1920 consideration | Operations, outage coordination and market teams | Congestion dollars saved. Alliant Energy identified $40.3 million in congestion cost reductions, 54% of total system congestion costs (DOE, April 2024) |
What proof gets the first deployment approved?
An options comparison on one named constraint, written in the owner's planning format, gets the first deployment approved. PPL's case shows the format. It started from a PJM market efficiency case with $23.5 million in annual congestion costs projected for 2025. PPL then compared three options (PPL, June 2025):
- Reconductor: 2 to 3 years, $0.5 million per mile, extended outages, about 34% more capacity.
- Rebuild: 3 to 5 years, $2 to $3 million per mile, extended outages, about 106% more capacity.
- DLR: about 1 year, under $1 million, no outages, 10% to 30% more capacity.
On the Juniata to Cumberland line, congestion fell from over $60 million to about $1.6 million between the winters of 2021-22 and 2022-23, according to the same PPL deck. PPL then expanded DLR from 2 to 14 lines since 2022, according to an industry coalition filing (November 2025).
Write the pilot so it ends in an operating decision. The DOE Liftoff report (April 2024) says each technology needs 6 to 12 large operational deployments to reach liftoff, and it names "perpetual piloting" as the trap. The same report found that only 7% of 2023 transmission and distribution capital spending went to advanced technologies.
How does the transmission owner recover the cost?
Cost recovery depends on how the owner books the spend. DOE explains the problem (April 2024): investor-owned utilities earn a return on capital spending, while operating expenses pass through at cost with no return. Cloud software is often booked as an operating expense. A low-capital, subscription-priced GET earns the owner no return, even when it saves customers money.
Three moves follow. Ask the rates team which structure it can capitalize before you set a price. Frame the project against a reliability or planning need, because DOE notes that an economic upgrade a transmission owner proposes on its own in an RTO carries the economic risk with no approved cost recovery. Use state routes where they exist, such as Utah's cost recovery provision or Montana's rate base treatment.
Interconnection rules shape the same planning calendar. Read what FERC Order 2023 changes for energy startups.
What should you do this quarter?
- Read the target owner's Order 1920 compliance filing. List each constraint where planners must explain whether an alternative technology was considered.
- Check the owner's Order 881 status. If the EMS upgrade is in progress, take DLR to the operations team that runs it.
- Check whether the owner's state has a GETs law with a planning or cost recovery clause.
- Build an options table for one named line: cost, time, outage need and capacity, in PPL's format.
- Prepare a NERC CIP security pack and an install plan that needs no outage.
- Bring regulatory and rates staff in before pricing, and agree how the spend gets booked.
- Write exit criteria that move the pilot into operations and into planning inputs.
To map the regulatory hooks and buyer teams at your own target transmission owners, start with The Diagnostic.