Research | Policy Briefs

Right of First Refusal

What is Right of First Refusal (ROFR)?

Right of first refusal (ROFR) is a right that gives incumbent utilities the option to have exclusive control over building, maintaining, and owning transmission lines in their service territory before a project is opened to competitive bidding. ROFR legislation has become an increasingly popular way for states to circumvent requirements of FERC Order 1000.

How does ROFR relate to FERC Order 1000?

In 2011, the Federal Energy Regulatory Commission (FERC) issued Order 1000, which repealed federal ROFR requirements and opened transmission projects to nonincumbent owners and operators through competitive bidding. The Order, however, only applies to federal projects and does not forbid states from enacting state ROFR laws. It also continues allowing utilities to pursue “immediate need” projects and upgrade systems without undergoing competitive bidding.

Why is it relevant now?

States are considering—or have passed—ROFR laws, largely at the behest of utilities who argue that the transmission industry is more efficient as a natural monopoly. ROFR advocates claim that Order 1000 slows transmission buildout by making interregional cooperation more difficult. Opponents argue that despite challenges, Order 1000 prevents anti-competitive behavior enabled by ROFR legislation.

What is the risk of ROFR legislation?

It limits competition and raises prices for consumers.

  • Utilities have historically operated as monopolies to leverage economies of scale and prevent high fixed costs from being passed to ratepayers. However, as the grid has modernized, this monopolistic structure has become less effective. Bidding for transmission projects has been shown to reduce costs by 20 to 30 percent, not only through the competitive nature of the process but also by setting cost caps to which utility transmission projects are not often subject.

It creates permitting roadblocks and slows transmission development.

  • ROFR laws can be poison pills for projects under development at the time of their enactment. For example, Texas’s ROFR law—passed in 2019—resulted in the cancellation of the NextEra’s competitively-bid Hartburg-Sabine transmission project designed to alleviate grid congestion. Initially approved in 2018, the project was only officially cancelled in 2023 after almost 4 years of delays. ROFR legislation in other states likewise stalls permitting and threatens hundreds of millions of dollars-worth of competitive transmission projects.

  • Furthermore, ROFR laws limit the construction of interstate transmission projects by forcing utilities to break projects apart to comply with state-specific legal requirements. Even states without ROFR laws (that are located in RTOs with states that do have them) end up incurring hundreds of millions of dollars of extra costs due to other states’ ROFR laws.

It relies on deceptive arguments that incumbent utilities serve ratepayers’ best interests.

  • Proponents argue that ROFR legislation allows local companies with vested interests in state or local economies—as opposed to (potentially) out-of-state independent transmission developers—to build transmission projects. However, these “local companies” are exclusively incumbent utilities. Unlike private transmission companies—which keep project costs low to maximize profit—utilities operate under a unique regulatory framework, whereby they pass on project costs to customers at a premium. Because utilities are guaranteed a profit by increasing rates beyond what is required to recover their costs, they are incentivized to pursue large and costly projects, regardless of economic efficiency.

How can lawmakers and regulators advance reliable and affordable transmission buildout?

Preserve competitive bidding on transmission projects

  • FERC’s proposed rule on transmission planning and cost allocation is crucial to addressing transmission roadblocks. But its reintroduction of federal ROFR backtracks on progress. Keeping federal ROFR out of the rule maintains competition and keeps rates low.

Clarify cost allocation for transmission projects

  • Currently, the majority of costs for transmission projects fall on power producers, who must agree to cover costs of transmission upgrades or development in order to connect their project to the grid. However, because transmission is a public good, a more equitable process of cost allocation is necessary. And because regional transmission lines cross state borders, any FERC Order updating cost allocation requires buy-in from states.

  • Potential reforms include a requirement for transmission providers to coordinate cost allocation with states and guidance on how tangible benefits translate to cost responsibility.

    • While FERC’s April 2022 NOPR on transmission planning and cost allocation addresses the former, it remains unclear how new transmission benefits will be quantified to determine cost allocation. FERC Order 1000’s vague requirement that transmission costs be allocated “in a manner that is at least roughly commensurate with estimated benefits” has already posed legal challenges and is not sufficiently addressed in the NOPR.

Engage states on the benefits of regional transmission

  • A key challenge to securing state buy-in on cost allocation is limited understanding of transmission benefits, especially in states that serve out-of-state load.

    • For example, Great Plains states hesitate to bear costs of transmission lines that originate in their states but deliver power to load centers on the East Coast. However, states in the Great Plains ultimately benefit from reverse power flows during periods of peak demand.

    • Furthermore, under a long-term planning scenario, transmission benefits all regions by facilitating power flow between regions simultaneously experiencing high and low demand. The importance of this feature increases as renewables penetration grows.

Establish a minimum transfer capability (MTC) to mitigate outages during periods of peak demand

  • During a December 2022 FERC workshop on establishing an MTC, stakeholders suggested that FERC require regions to be able to transfer 15% of power to neighbors during peak demand.

  • Likewise, the Building Integrated Grids with Inter-Regional Energy Supply (BIG WIRES) Act proposed by Sen. John Hickenlooper and Rep. Scott Peters would establish a 30% MTC.

Prevent speculative projects from clogging interconnection queues

  • FERC Order 2023 on interconnection queue reform addressed half of this problem by increasing study and commercial readiness deposits and penalizing projects that withdraw from the queue.

  • The other half of the solution requires greater transparency from grid operators. Because RTOs do not publicly disclose costs and technical requirements of interconnection at different grid points, the only way for developers to access this information is by submitting an interconnection request (which they may later withdraw after an interconnection study reveals cost-prohibitive requirements). This practice—along with early submissions to hold spots in increasingly long queues—has exacerbated wait times. Requiring RTOs to provide information upfront—rather than after project submission—can alleviate wasteful processes.

Finalize expansion of federal backstop siting authority

The Infrastructure Investment and Jobs Act expands FERC’s ability to use backstop permit authority where a state has (1) not made a determination on an application after one year; (2) conditioned its approval such that the proposed project will not significantly reduce transmission constraints or congestion or is not economically feasible; or (3) denied an application. In order to implement this authority, FERC must finalize its proposed rule on permitting interstate transmission facilities.