Need for Speed: An Analysis of Speed to Market and Cost Results of Competitive Transmission: Part 1—Introduction
This is the first in a five-part series examining the performance of transmission competition relative to the outcomes of similar incumbent utility transmission development. The series will focus on the timing and cost of transmission competition in the United States, reviewing relevant literature, evaluating outcomes of similar competitive transmission mechanisms in other countries, and concluding with policy recommendations.
The electric transmission sector in the United States is undergoing significant transformation to meet growing demands for reliable, affordable, and cleaner energy. A key consideration in this transformation is the availability and efficiency of the nation’s transmission infrastructure. Timely and cost-effective transmission development has become a central policy challenge, as delays or cost overruns can directly affect reliability, rates, and decarbonization goals. One major driver of transmission expansion has been FERC Order 1000, issued in 2011 to reform transmission planning and cost allocation processes and promote competition. Prior to that, incumbent utilities—typically investor-owned utilities (IOUs) with established geographic monopolies—held a federal ROFR for new transmission projects needed within their monopoly service territories (with limited exceptions). In addition to mandating regional transmission planning processes and articulating guidance regarding cost allocation, Order 1000 eliminated the federal ROFR for certain regionally beneficial projects, opening the door for non-incumbent developers to bid on transmission developments through open solicitations managed by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs).
Issued in 2024, FERC Order 1920 builds upon the framework established under Order 1000, providing clarification and refinement to transmission planning, cost allocation, and regulatory compliance, expanding the universe of transmission needs and projects subject to competition.
This piece is part of a multi-part analysis evaluating the cost and timing outcomes of competitive transmission development as compared against incumbent utility development. Using empirical data from both in-service and ongoing projects, the analysis compares cost performance, timing, and risk outcomes across development models. By examining the relevant literature, available data, and case studies, this piece provides a comprehensive overview and detailed assessment intended to help policymakers optimize transmission development during rising electricity needs driven by electrification, generation changes, and data center growth.
Background
Prior to FERC Order 1000
The genesis of the collective U.S. electric system started as neighborhood-sized grids severely limited in geographic scope. With legal and technological changes came the expansion of existing electric systems through organic growth and consolidation of existing operations. The growth and expansion of these systems was driven by cost reductions from technological innovation and increased demand coupled with correlated economies of scale. IOUs sought (and states granted) defined service territories or laws that equated to de facto geographic monopolies. Out of concern that these IOUs would provide poor service or charge extravagant prices with their newfound monopoly, state legislatures created regulatory agencies tasked with ensuring quality service and reasonable rates, the latter being set based on a utility’s cost to serve. The combination of a geographic monopoly and cost of service regulatory principles enabled IOUs to recover the reasonable costs of serving the public, including a return of and on their investments. However, these structures led much of the country’s budding electric grid to become heavily balkanized, with limited transmission interconnections between IOUs resulting in foregone investments in beneficial transmission facilities and underuse of generating assets. While there are notable examples to the contrary, the buildout of America’s electric grid during the 20th century resulted in hundreds of fractured (albeit nominally connected) IOUs. For decades, IOUs had little financial incentive or regulatory encouragement to engage with one another to reduce costs or to enhance the broader grid, and about 25 percent of electricity customers were served by hundreds of municipal, cooperative, state, and federal utilities. These utilities vary widely in size.
Starting near the end of the 20th century, policymakers at the state and federal levels began efforts to encourage competition in the supply of generating services and to reduce the balkanization of the grid. Interest in increased electricity competition and concern for grid reliability and economics drove federal and state legislative action that resulted in a greater focus on the country’s transmission system. FERC took note of the shortcomings of current transmission planning efforts, including the inherent conflicts in incentives for utilities to build out a more interconnected grid, resulting in a number of reforms including Order 1000, which was slightly amended and refined in 2012.
Following FERC Order 1000
Order 1000 was intended to “address remaining deficiencies in transmission planning and cost allocation processes so that the transmission grid can better support wholesale power markets and thereby ensure that Commission-jurisdictional services are provided at rates, terms and conditions that are just and reasonable and not unduly discriminatory or preferential.”
Major areas of reform included:
- Regional transmission planning requirements and clear guidelines for transmission cost allocation
- Tariffed processes to consider state and federal public policy in transmission planning
- Interregional transmission coordination between planning regions
- Removal of a federal ROFR for certain new transmission facilities
The latter reform introduced competition to construct transmission facilities, with FERC concerned that status quo incumbent utilities with retail franchises having ROFRs to construct all facilities would “undermine the identification and evaluation of more efficient or cost-effective solutions to regional transmission needs.”
Literature Review and Previous Studies
While earlier academic papers touched on the economic opportunities presented by increased competition in transmission, analytical literature on competitive transmission in the United States shows a polarized debate: Proponents highlight cost savings and innovation, while critics emphasize delays, uncertainties, and hidden costs with competitive projects.
A comprehensive report published by The Brattle Group in 2019 analyzed 16 competitive transmission solicitations in the United States and international experiences with transmission competition, finding average proposed cost savings of 40 percent below ISO/RTO estimates or competing incumbent bids, with expected final savings of 20 to 30 percent after accounting for escalations. While solicitations in RTOs indicated significant possible savings, many competitive projects in the United States were not in service at the time of the study. For this reason, the Brattle report used benchmarks from the United Kingdom (23 to 34 percent savings across 15 projects) and Brazil (20 to 40 percent across over 50,000 kilometers of lines) to support its ultimate conclusions and findings.
Concentric Energy Advisors issued its own analysis later that year in response to the Brattle report. Concentric criticized Brattle’s use of projects that were not yet in service, arguing that exceptions to cost cap commitments could cause savings from the procurement process to erode. The response further noted the importance of timing in transmission development; however, it did not seriously study the issue. Instead, Concentric conducted a case study of the “longest solicitation” of available competitive projects, attempting to highlight the Brattle report’s purported shortcoming and giving the impression that Concentric’s case study was a representative result.
Brattle subsequently responded to Concentric’s study, stating that its criticisms “are based on inappropriate and misleading cost comparisons, a misrepresentation of the available transmission cost data and facts, and a misunderstanding of our analysis.”
A 2022 Concentric report featured case studies of six transmission projects won by competitive developers across four planning regions that were either “in service or in advanced development.” Based on these six projects, Concentric concluded that “Order No. 1000 competitive solicitations have not been successful in driving cost savings and have added delays to the development of transmission infrastructure.” Although the study included a selection of competitive transmission projects, researchers did not attempt to compare the results of competitive processes (regarding either cost or timing) to similarly situated incumbent-developed projects.
Concentric expanded upon prior analyses in a 2024 update, incorporating more projects and challenges while underscoring ongoing debates over realized versus proposed savings.
A 2021 working paper from the MIT Center for Energy and Environmental Policy Research discusses Order 1000’s slow adoption, with competition applied selectively and showing promise for benefits although diffusion remains limited due to regional variations. Author Paul L. Joskow stated that Order 1000 “has not realized its promise”; however, that perspective relates to a perceived failure in the planning expectations of Order 1000 rather than the removal of a federal ROFR. With respect to transmission competition, the author noted that “competitive procurement does make a lot of sense,” and made suggestions to regulators to improve competitive outcomes.
The Developers Advocating Transmission Advancement Coalition has produced a number of analyses regarding Order 1000, including a 2025 whitepaper arguing that competitive processes create inefficiencies, with illusory cost caps and inadequate consideration of siting risks leading to overruns and terminations. R Street has previously responded to this analysis as well as a similar one by the Alliance for Innovation and Infrastructure, which focused on timing considerations in competitive transmission.
The literature suggests that while competition can reduce costs through competitive procurement, it also risks higher variability. Savings estimates range from 15 to 60 percent in supportive studies, tempered by critiques of real-world implementation and caution regarding in-service observations.
Data and Methodology
As noted previously, earlier studies were limited by a lack of in-service project data. Our analysis updates the literature by incorporating a larger sample of projects with observed outcomes.
This series relies on two core datasets developed from primary sources that track transmission project outcomes across major U.S. transmission planning regions: one focused on projects developed by incumbent utilities and the other on projects awarded through competitive solicitations. If an incumbent wins a competitive solicitation, we still consider that project in our competitive samples. The authors have carefully structured these datasets to provide a consistent framework for comparing cost performance, timelines, and overall development outcomes. Our analysis includes all incumbent projects greater than $50M with in-service dates from January 2018 through Q3 2025 (and for MISO and SPP as of May 2026). For the timeline sample, we isolated greenfield transmission line projects from the broader population of large incumbent investments, given the additional efforts required for greenfield transmission development.
The incumbent dataset captures transmission projects developed by existing utilities within their monopoly service territories that are not subject to competitive solicitations. Typically, these projects are planned and executed under traditional regulatory structures where developers are obligated to serve and recover costs through their own regulated rates. Our analysis compiled project-level information across multiple regions, including project scope (e.g., voltage, size), estimated and final capital costs, and resulting cost efficiency metrics (e.g., cost per mile). From these data, we have also developed aggregated regional calculations demonstrating the comparison between initial estimates and final outcomes. Because incumbent utilities report detailed financial information through regulatory filings, this dataset benefits from relatively standardized and verified final cost data—particularly for projects that are already in service, though detailed timeline reporting on incumbent projects is comparatively lower quality.
The competitive dataset tracks projects awarded through regional solicitation processes. Proposed by a range of developers, these projects are selected through regional planning processes based on cost, timeliness, experience, risk and other evaluation criteria. To assess these projects, the authors have gathered information including initial bid estimates, cost caps where applicable, and updated cost information as projects progress. It also captures differences between planning-stage estimates and developer-proposed costs. Competitive project data is less uniform across regions than the incumbent dataset because reporting requirements vary by region, and some projects are still under development. This means final cost data may be incomplete or evolving.
Both datasets draw on a combination of regulatory filings, RTO/ISO reports, and publicly available project documentation. Incumbent data is often sourced from regional project cost reporting documents. Competitive data for initial cost and expected in-service dates are sourced form selection reports at the time of project award, while competitive final costs are based on formula rate filings from the in-service year.
Data availability and quality vary significantly across regions, with some (i.e., SPP, MISO) providing relatively consistent and transparent reporting that enables tracking of project costs and timelines while others, like PJM and CAISO, face limitations due to inconsistent reporting practices, confidentiality constraints, or lack of historical data. As a result, the samples rely on region-specific treatments and conservative assumptions, prioritizing projects with verifiable and comparable data while excluding those with incomplete, inconsistent, or non-comparable cost and timeline information. These sources, treatment, and methods will be detailed further throughout this series.
For its overall methodology, our analysis applies a consistent framework to evaluate transmission projects across regions, development models, and project types. Given the wide variation in project size, geography, and complexity, the methodology focuses on standardizing the data so that comparisons reflect meaningful differences in performance rather than structural inconsistencies. We examine projects at multiple stages of their lifecycle—from early planning through development and completion—allowing for a comprehensive view of how outcomes evolve over time. This approach supports both cross-sectional comparisons and broader trend analysis while enabling further understanding and clear quantitative support of the various case studies.