A new report from the consulting firm Grid Strategies finds that a one-year delay on high-dollar, large-scale electric transmission projects can drive up consumer costs by 15% to 37% in lost benefits.
The Nov. 12 report, commissioned by the pro-transmission trade group WIRES, comes as utility ratepayers have become increasingly sensitive to rising power bills fueled in part by electricity demand from data centers.
"Of course, the mantra in Washington is 'speed to power' to improve our chances in the AI race with China," Rob Gramlich, the Grid Strategies president and report coauthor, said during a Nov. 13 interview. "In this report, we really wanted to focus on consumers' costs because you can dilly-dally for years over transmission plans, and a lot of people seem to lack the urgency that we think is needed."
Review finds significant delay-related costs
The Grid Strategies analysis is based on a review of eight different transmission portfolios across the 15-state Midcontinent ISO, 14-state Southwest Power Pool, New York ISO and Electric Reliability Council of Texas Inc. regions. With a focus on ratepayer impacts, the analysis excluded climate benefits where possible.
For each portfolio, the analysis calculated what one year of foregone annualized net consumer benefits would amount to if each portfolio experienced a one-year delay beyond its target in-service date. Examples of delay-related costs included system efficiency losses, delays in connecting more affordable generation, siting and permitting delays, increased materials-related costs, and job losses.
The Southwest Power Pool's latest Integrated Transmission Planning study — a $7.7 billion planned portfolio of projects approved in 2024 with a benefit-cost ratio of 8.23 — led all portfolios with $7.7 billion in estimated consumer cost increases for each year of delay. The portfolio includes 89 projects that cover 2,333 miles of new transmission and 495 miles of rebuilt transmission, with total estimated benefits of $84 billion.
ERCOT's Competitive Renewable Energy Zone effort in West Texas, proposed in 2005 and completed in 2013, ranked second with $6.3 billion in estimated one-year delay costs.
Across the eight studied portfolios, the analysis found that every one year of delay for $1 billion invested in "well-planned, large-scale transmission" would cost consumers between $150 million and $370 million in lost annualized net benefits, even after accounting for the cost of transmission.
The report acknowledged a lack of comprehensive data on project cost escalations. However, the analysis cited two recent examples.
Completion of Avangrid Inc.'s New England Clean Energy Connect project — a 145-mile, 320-kV high-voltage direct-current transmission line capable of moving 1,200 MW through Maine, from Canada to the broader New England market — was delayed by roughly two years due to a Maine ballot initiative and legal challenges. The delay added more than $500 million to the project's overall cost of $1.5 billion, a nearly 50% escalation, the report noted.
The 102-mile, 345-kV Cardinal-Hickory Creek transmission line linking Dubuque County, Iowa, and Dane County, Wisconsin, which was fully energized in late 2024, also experienced a roughly 25% cost increase amid legal disputes, the report observed. The $1 billion project — co-owned by Dairyland Power Cooperative, ITC Midwest LLC and American Transmission Co. LLC — will support 160 new generation projects representing approximately 17 GW of capacity. The line was first proposed with an estimated cost of $798 million and a 2020 target in-service date.
"Consumers benefit most when transmission projects are energized as soon as possible," the report said. "The affordability of electricity supply depends in no small part on timely execution of efficient and cost-effective transmission expansion."
'Choices' for policymakers
Gramlich said policymakers have a range of available options to help ensure projects get built on time. He specifically urged timely implementation of the Federal Energy Regulatory Commission's Order 1920, which requires regional grid operators to look further into the future in developing long-term transmission plans.
"FERC has a choice on that, and each of the regions and the state regulators in those regions have choices on that," Gramlich said.
Interregional planning "is also a choice" that regional grid operators can make, he added. In addition, federal lawmakers are weighing an interregional transmission planning requirement as part of ongoing efforts to secure a bipartisan compromise on permitting reform legislation.
Furthermore, "there are just a lot of choices to be made by independent developers and permitting authorities on lines around the country," Gramlich said. "So, I think it's a timely question for all of those entities. They have the ability to accelerate transmission development, but they also can sit on their hands if they want to."
