A group of 13 "high value" transmission projects spanning multiple regions in the Eastern Interconnection could generate up to $15.3 billion in net system value through 2050, according to a study released Tuesday. The analysis, titled *Powering Growth and Affordability: The Role of Transmission in Economic and National Security*, was prepared by S&P Global's CERA Consulting for the Electricity Customer Alliance, National Grid, and Converge Strategies. Beyond dollar savings, the projects would reduce retail electricity rates, strengthen system reliability, and boost resilience to extreme weather events, the report states.
The study examined potential transmission lines across the Northeast, PJM Interconnection, Southeast, MISO's southern region, and Southwest Power Pool. Researchers modeled scenarios combining base and high demand cases with constrained and unconstrained transmission options—the constrained scenario excludes new interregional projects. Under the base demand, unconstrained case, the Eastern Interconnection footprint would see roughly $12.4 billion in net present value at a 1.77 benefit-to-cost ratio. PJM would capture $6.7 billion in benefits over 40 years, followed by SPP and MISO South at $1.9 billion, the Southeast at $851 million, and the Northeast at $393 million. The high demand scenario pushes benefits higher, particularly for the Northeast and Southeast regions. The study identified 12 potential high-value projects under base demand and 13 under high demand.
The report states that changes in generation capital expenditures represent the largest contributor to net present value, followed by production cost savings and avoided transmission costs. "Transmission expansion enables access to lower-cost remote resources, reducing the need for more expensive local generation builds," the authors write. The constrained case, which lacks new interregional transmission, significantly reduces the benefits, according to the study. Jeff Dennis, ECA executive director, said the study offers a customer-centric perspective on transmission expansion: "Customers need more transmission capacity," he noted, "but they're in this conundrum because they see transmission costs going up." The analysis, he explained, shows how refocusing on projects that deliver the most net benefits can address this tension.
The study's findings align with analysis from the U.S. Department of Energy and other researchers showing how targeted transmission projects can lower costs by creating pathways for cheaper electricity to flow to higher-cost areas. The transmission links can also eliminate the need to build power plants and local transmission to serve constrained regions, the report explains. Using advanced transmission technologies such as dynamic line ratings could produce significant benefits that would likely offset higher initial costs, according to the authors. The report notes that power supply construction in the U.S. is at its highest level in recent history, with 67 GW currently under construction—including 27 GW of solar, 17 GW of battery storage, 15 GW of wind, and 9 GW of gas-fired generation.
Dennis, who previously served as deputy director of transmission in DOE's Grid Deployment Office, outlined several solutions for spurring interregional transmission development. These include allowing large customers to invest directly in transmission, opening opportunities for merchant transmission, and advancing permitting reforms currently under discussion in Congress. The study also calls for transmission policy reforms to ensure planning processes prioritize projects that deliver the most future value to customers rather than encouraging smaller projects that may add cost without adding much capacity. The bottom line: strategic transmission investments can simultaneously cut costs, improve reliability, and prepare the grid for growing electricity demand.