Interregional transmission creates net savings of $680 million per year, but could save $790 million more
We’d like to share our recently published study that analyzes hourly energy transfers across thirty-two US transmission interfaces, from 2014 to 2023. By comparing real-time energy prices in the exporting and importing regions, it gauges the economic efficacy of transactions. Unlike many studies, this analysis uses empirical data to assess interregional transmission value instead of using models.
Electricity trade between regions can help lower costs by tapping least cost generation sources and increasing use of the existing grid, spreading costs over more kilowatt-hours. It can also boost reliability during extreme weather events and help deliver more power where it is needed, a critical issue as new data centers drive up demand.
But these benefits can be eroded by market flaws, barriers, and inefficiencies, reducing total benefits by hundreds of millions of dollars.
The study finds that transfers saved $1.2 billion per year by moving energy from lower to higher-priced regions. But almost half of the value of these gains was lost due to uneconomic transactions in other hours, resulting in a net savings of $680 million per year. Much of this value, and more – up to $790 million – could be regained by solving these problems.
One important aspect of the study is that it focuses on electric sector cost savings that could derive from operational changes to the current infrastructure, by changing software and policies rather than hardware. These savings could be achieved while avoiding the challenges of building new transmission lines.
The study discusses two primary mechanisms for increased value (or equivalently, increased savings).
The first mechanism is to simply reduce trade when conditions are uneconomic. Uneconomic is defined as hours in which energy flows from a high price region to a lower price region. The second mechanism is to trade more power when prices are favorable, and head room is available to expand the flow of energy on the existing transmission infrastructure.
The study found that a quarter of all real-time interregional electricity transactions were uneconomic -- that is, that high priced power was imported despite lower priced generation being available. Moreover, most interfaces were regularly underutilized, even when the energy being exchanged was economical.
Though most interfaces saw 10% to 40% of energy flows classified as uneconomic, the most extreme case was as high as 81%. Fees and other transaction costs can add as much as $10/MWh to prices, but the observed price differences are often far greater than those costs. This uneconomic trade, worth $550 million per year on average, suggests serious market inefficiencies.
This figure summarizes the results.
Savings could be recaptured by eliminating uneconomic power flows and increased by encouraging more economic transactions when transfer capacity is available. Increasing the energy traded by 20% when the price differential is greater than $20/MWh would save $240 million per year. Additionally, much greater savings could be captured by pursuing additional opportunities identified in the research but classified as more speculative.
While previous studies and market monitors have documented inefficiencies in specific market seams, this study is the first with coverage across many regions, using unified and well documented methods and a long time series of empirical data. The study covers approximately 50 GW of transfer capacity, roughly 60% of national transfer capacity. The sample suggests that the potential savings would be potentially much larger if changes were implemented nation-wide.
The study also points out a possible refinement to systems modeling. While capacity expansion models are used to optimize transmission build-out and operation, they rarely consider empirical data on actual transmission operation. They are instead idealized representations of the electricity system, and their designs omit or only roughly integrate market seams inefficiencies.
A large price spread between regions, without economic power flows between them, is a sign of economic inefficiency, and an opportunity for savings. Customers would benefit from the development and deployment of solutions that improve interregional transmission operations, in parallel with robust transmission infrastructure planning.
While electricity sales within a region can be optimized by a regional market, trades across seams require intentional coordination and management among multiple parties. Barriers to trade can be physical, such as a lack of power lines or congestion on the grid, but they can also be economic and structural, such as fees and tariffs, and they can be operational, with poor coordination between grid and market managers.
Improving interregional coordination represents a major challenge and would incur costs. The goal of our study was to quantify the opportunity, not to estimate the costs of meeting the coordination challenge. Our study discusses a number of possible solutions to the coordination challenge have been proposed by others, including market-based optimization of available interregional transmission capacity, improved price forecasting, shorter time gaps between the transaction window closing and dispatch, developing consistent methods for calculating transfer capability, and eliminating transaction fees.
The study, “Interregional Electricity Transmission in the United States: Realized Savings and Opportunities for Increased Value, 2014 to 2023” appears in The Energy Journal and is freely available. For inquiries, please contact Julie Mulvaney Kemp, [email protected], or Dev Millstein, [email protected], at Berkeley Lab.
This work was supported by the U.S. Department of Energy’s Office of Critical Minerals and Energy Innovation under Lawrence Berkeley National Laboratory Contract No. DE-AC02-05CH11231.