interregional electricity trade has a measurable economic basis in U.S. power markets: it allows electricity to move from lower-cost regions toward higher-cost regions when transmission capacity, market rules, and system conditions permit. The evidence available as of August 27, 2026, points to material cost savings, but it also shows that the benefits are uneven and partly constrained by inefficient flows, underused transfer capability, and planning limits.
The subject is not theoretical. Regional transmission organizations, balancing authorities, and utilities already exchange electricity across market and operating boundaries. What remains under study is how much value is being captured, how much is being left unused, and how proposed expansion would affect costs and emissions under different demand and policy cases.
What interregional electricity trade Measures
interregional electricity trade In Market Data
A 2026 study by Safavi and co-authors analyzed 32 U.S. transmission interfaces over the 2014-2023 period. The study found average realized cost savings of at least $1.226 billion per year from power moving between regions with different prices. That estimate is based on observed trade and price differences, so it reflects real market behavior rather than only a planning model.
The same research also found that the system did not capture the full available economic value. Nearly half of potential gains were lost to inefficiencies, including uneconomic flows and under-utilization of available transmission capacity. Uneconomic flows accounted for 26% of interregional electricity flow by volume, with a wide range across interfaces, from 11% to 81%. That variation suggests that institutional rules, scheduling practices, congestion patterns, and market seams can matter as much as the physical line rating.
Why Price Differences Matter
The economic logic is direct: if one region has lower wholesale electricity prices than a neighboring region, a transfer can reduce total production costs if transmission is available and the transfer is scheduled in the economically efficient direction. The 2026 study estimated that a 20-percentage-point increase in utilization of available capacity during hours when the price differential exceeds $20/MWh could create $238 million per year in added gains.
That figure should not be read as a guaranteed saving for every consumer bill. Wholesale savings can be affected by congestion charges, hedging, retail rate design, generator revenue changes, and the cost recovery of new infrastructure. Still, the finding gives planners a quantitative signal: existing assets may have untapped value before any new line is built.
Economic Value From Added Transmission
Measured Value Per Gigawatt
Recent peer-reviewed work strengthens the case that transmission additions can carry high market value in specific locations. A Nature Communications study covering 2012-2022 found that many added interregional or cross-interconnect links had a median value of about $116 million per GW per year, based on observed market conditions and the value drivers of transmission capacity Nature Communications.
Berkeley Lab’s 2023 market-data review reported that additional transmission expansion could provide values greater than $20/MWh in some locations, with certain strategic inter-interconnection or system-operator links valued at roughly $175 million per year for each added 1 GW Berkeley Lab. These values are not uniform across the grid. They depend on where congestion occurs, how often price spreads appear, the generation mix on each side of an interface, and how the line is used during high-stress hours.
Cost Savings Are Scenario Dependent
DOE’s October 2024 Transmission Impact Assessment, as reflected in the supplied research, estimated that a more ambitious inter-regional transmission buildout could yield $320 billion in present-value cost savings through 2050 compared with restricted transmission growth cases. That is a planning result, not a completed market outcome. It depends on assumptions about demand growth, generation additions, retirements, fuel prices, carbon policy, siting success, and the cost of building lines.
This is where U.S. grid savings from transmission expansion connect with the wider policy debate. A line that is valuable in a model still has to clear permitting, cost allocation, land-use, reliability, and interconnection tests. Those barriers can delay or reduce the expected value even when the economic case is strong on paper.
Environmental Findings And Their Limits
Emissions Reductions In Planning Studies
The environmental case for interregional electricity trade rests on the idea that larger transfer capability can help lower-emitting generation reach more load centers and reduce reliance on higher-emitting local generation during some hours. In the DOE Transmission Impact Assessment cited in the supplied research, increased regional and interregional lines were associated with about 3,420 million metric tons of cumulative U.S. power-sector greenhouse gas reductions by 2050. The same scenario estimated climate benefits of $730 billion and health benefits of $50 billion.
Those are modeled benefits, not measured reductions from a completed national buildout. They depend on the generation fleet that is actually built, the timing of fossil retirements, future load growth, and whether new lines are operated in ways that displace higher-emitting output. Health-benefit estimates in energy studies are population-level economic estimates, not medical guidance; readers seeking clinical eye-health material in the same publishing network can use Wills Glaucoma.
High-Demand Cases Require Larger Networks
The 2024 National Transmission Planning Study, as summarized in the research notes, found that under high demand growth and ambitious carbon targets, interregional transmission capacity by 2050 could need to reach up to about 3.9 times the 2020 level. In high-demand cases with ambitious climate policy, the same study projected cumulative avoided CO2 emissions of 14-16 billion metric tons. Under lower-demand scenarios, avoided emissions were estimated at 3-4 billion metric tons.
The range is meaningful. It shows that environmental outcomes are not determined by transmission alone. Demand growth, electrification rates, generation choices, and policy stringency change the scale of avoided emissions. Transmission can expand the operating options available to grid managers, but it does not by itself determine which generators are built or dispatched.
Implementation Barriers In U.S. Grid Trade
Market Seams And Utilization
The largest near-term opportunity may be improving the use of infrastructure that already exists. The 2026 findings on uneconomic flows show that interregional electricity trade can fail to follow price signals in a sizable share of hours and interfaces. Better scheduling, market coordination, and congestion management could raise realized value, though the research provided does not specify a single reform that would solve all interfaces.
Under-utilization is also a planning problem. If available transfer capability is not used when price spreads are large, consumers may pay more than necessary for local generation. Yet raising utilization must still respect reliability constraints. Operators cannot treat every megawatt of nominal capacity as freely available at all times because contingencies, voltage limits, thermal limits, and operating reserves affect safe transfers.
Building Lines Is Not Only An Engineering Task
New interregional capacity can be expensive and slow to develop. The supplied research gives economic values for added capacity, but those values have to be weighed against project costs, siting risk, permitting time, landowner concerns, and cost-allocation disputes among states and customer classes. These are implementation barriers, not reasons to dismiss the measured benefits.
There is also a timing issue. A line that becomes available after demand growth or generator retirements have already changed system conditions may deliver a different value than the one estimated when planning began. Evidence-based transmission policy therefore needs periodic reassessment using current market data, not one-time assumptions.
interregional electricity trade In U.S. Grids
What The Evidence Supports
The available evidence supports a cautious but clear assessment. Existing interregional electricity trade has produced observed economic savings, and several studies find that added transfer capacity can have high value in selected U.S. interfaces. The strongest figures in the research are not general promises; they are tied to specific study designs, time periods, interfaces, and scenarios.
The environmental evidence is also significant but more conditional. Large emissions reductions appear in national planning studies when transmission growth is paired with high clean-energy deployment, demand assumptions, and policy cases. If those conditions change, the emissions outcome changes as well.
For grid planners and policymakers, the practical lesson is that both operations and construction matter. Better use of existing interfaces could recover part of the value now lost to inefficient flows. Targeted expansion could add further savings where price spreads and congestion justify the cost. The evidence does not support treating every proposed line as equally valuable, but it does support careful regional and interregional analysis based on measured prices, congestion, reliability needs, and emissions impacts.