Infrastructure Bill and transmission
The $1.2 trillion infrastructure bill that President Biden signed into law in November moves the needle in favor of enhancing regional transmission construction, but it is not expected to have a material effect on the pressing or long-term need for additional transmission capacity to facilitate the transition from fossil fuel to renewable energy.
The bill makes it a little easier to override a state’s opposition to permitting an interstate line within its borders.
It also permits the US Department of Energy to provide relatively low-dollar grants and to invest in, finance or contract for new interstate transmission capacity and the hardening of the transmission grid.
Meanwhile, the Federal Energy Regulatory Commission is moving separately to try to boost transmission capacity on a regional basis and address how the costs of new capacity additions are borne by interested parties, and the RTOs that run regional sections of the US electricity grid are taking steps to deal with bloated interconnection queues.
FERC Siting Authority
Unlike the Natural Gas Act, the Federal Power Act does not give FERC authority to issue a certificate to a utility that would allow it to use federal eminent domain power to push through a new transmission line.
The states retain the right to approve the siting of transmission lines. Therefore any state can stifle construction of a transmission line that would connect to the interstate grid and move electricity to customers in other states.
In 2005, Congress added a provision to the Federal Power Act that directed the Department of Energy, in consultation with the states, to identify certain “national interest corridors” with constrained transmission capacity. If a transmitting utility applied to a state commission for a certificate to construct a new transmission line and the state commission failed to act within one year, then FERC could issue a permit approving the line and allowing use of eminent domain if it determined that the new line would significantly reduce transmission congestion. This has become known as FERC’s “backstop” authority.
This backstop authority has never been used successfully. A federal appeals court in 2009 rejected FERC’s view that a state’s denial of a certificate within one year to build the new line equated to a “failure to act“ under the new Federal Power Act provision. Thus, if a state formally rejected a new line proposal — as opposed to merely sitting on the request — FERC could not override the rejection.
The market interpreted this as a barrier to an effective federal eminent domain backstop authority. No transmitting utility has sought to use this authority, and the Department of Energy never identified any additional national-interest corridors beyond two that it had already designated.
The new Infrastructure bill amends the Federal Power Act to make clear that FERC has backstop authority to use federal eminent domain in national interest corridors even in cases where a state formally rejects a proposed new line as well as merely fails to act on the request, or where the state adds conditions to its approval that would not permit significant reduction in transmission capacity constraints.
The Department of Energy is to make national interest corridor determinations every three years.
The new law makes clear that a national-interest determination can include a finding that the designation would enhance the ability of facilities that generate or transmit firm or intermittent energy to connect to the electricity grid or would be in the interest of national energy policy.
It remains to be seen whether DOE will designate national interest corridors based on projected paths, for example, where there may be no current transmission but where there is potential for substantial wind and solar capacity development and a likely demand for this potential energy in distant load centers.
While this modification to permit FERC’s backstop siting and eminent domain authority is an improvement from the existing law, the path to permitting and eminent domain will still be a long and complicated process.
DOE still has to do a study in consultation with affected states and Indian tribes and make numerous findings before designating a national interest corridor. Then a transmitting utility has to ask for a permit from the affected state, which has a year to act. After a rejection or inaction by the state, the transmitting utility has to apply to FERC for a construction permit containing a right of federal eminent domain by, among other things, demonstrating to FERC that it has made a good faith, though unsuccessful, effort to engage with landholders and other stakeholders early in the permitting process.
Transmission Construction Facilitation
Perhaps the most significant transmission–related component of the infrastructure bill relates to a new “transmission facilitation program.”
Under this program, “eligible projects” consisting of new high-voltage interstate transmission lines capable of transmitting at least 1,000 megawatts or upgrades to existing interstate transmission lines capable of transmitting at least 500 megawatts, and the related non-generating facilities, are eligible for a range of financing enhancements from the Department of Energy. The US Treasury is authorized to lend up to $10 billion to DOE to be used to finance eligible projects, with no more than $2.5 billion to be funded in outstanding repayable balances at any one time.
DOE can either enter into a transmission capacity contract with an eligible project in order to facilitate completion of the project, make a loan to an eligible project for the costs of carrying out the project, or participate in designing, developing, construction, operation, maintenance or ownership of the eligible project.
When deciding to enter into a transmission capacity contract, DOE can either make fair market value payments for the use for the transmission capacity, with the amount to be paid on a scheduled basis or as a single payment. DOE cannot contract for more than 50% of the total transmission capacity of an eligible project. DOE is expected to become an “anchor” customer for new lines for which it contracts for capacity, thereby encouraging others to use the remaining capacity and facilitating private financing of the new line.
DOE has been directed to terminate the capacity contract as soon as practical after determining that enough other projects have signed up for transmission capacity to make the new line financeable. Accordingly, at some point DOE can be expected to sell its contracted capacity and recover its investment.
The other way DOE can serve as a catalyst for new transmission lines is to make loans. The amounts loaned are to be recovered from transmission owners through rates they charge for use of the new transmission capacity.
Given the time it will take for DOE to establish a “transmission facilitation program” and the time it has traditionally taken to complete the paperwork and authorization for DOE lending, even if successfully implemented, this program is unlikely to be effectively used in the very near term. It is a start. However, the dollar limitation on its use will not by itself meet the pressing need for new and upgraded high-voltage transmission, which many experts have projected in the hundreds of billion dollars over the next 10 to 20 years in order to approach the massive amounts of transmission needed to bring renewable power to the places that need the power to reduce or eliminate their carbon footprints.
Grid Resiliency Grants
DOE, after implementing the program by May 14, 2022, is authorized to issue up to $5 billion in grants from 2022 through 2026 to “eligible entities” directly and to states and Indian tribes for the benefit of eligible entities in their respective jurisdictions for technologies and equipment to “harden” the transmission grid to avoid “disruptive events,” including wildfires.
The grants can be used for all of the following:
- weatherization technologies and equipment;
- fire-resistant technologies and fire prevention systems;
- monitoring and control technologies;
- the under- grounding of electrical equipment;
- utility pole management;
- the relocation of power lines or the reconductoring of power lines with low-sag, advanced conductors;
- vegetation and fuel-load management;
- the use or construction of distributed energy resources for enhancing system adaptive capacity during disruptive events, like microgrids and underground cabling.
Eligible entities include grid operators, storage operators, generators and transmission owners, distribution companies and fuel suppliers.
Grants to individual entities cannot exceed the amount spent by the entity in the past three years to reduce the consequences of disruptive events.
DOE is supposed to prioritize projects that it believes will produce the greatest community benefit.
At least 30% of the available grant money must go to small utilities that sell fewer than four million megawatt hours per year.
Each grant awarded to a state or Indian tribe — to make grants, in turn, to eligible entities within their jurisdictions — is subject to a 15% matching requirement.
The grants cannot be used to construct a new generating facility or large-scale battery storage facility unless it is used to enhance system adaptive capacity during disruptive events.
DOE is supposed to award 50% of the grants directly to eligible entities and 50% to states and Indian tribes. Except for small utilities, there is a 100% matching requirement for an eligible entity that receives the grant.
The legislation also authorizes up to $5 billion during the period 2022 through 2026 to be given to state and local governments, Indian tribes and public utility commissions for research, development and demonstration projects to develop innovative approaches to transmission, storage and distribution infrastructure to harden and enhance resilience and reliability.
The bill also authorizes up to $1 billion over the same period to improve reliability of the grid and electricity supply in rural areas and up to another $1 billion to help with such things as siting of distribution lines, reducing greenhouse gas emissions from generating facilities and developing microgrids in rural and remote areas.
Funding will be subject to a cost-sharing mechanism of about 20% of the total cost of the activity. The government will pay the remaining share of the cost.
Apart from the infrastructure legislation, FERC is moving independently to encourage faster construction of regional transmission capacity over the longer term.
FERC has long recognized that the historic structure of the interstate transmission system was not conducive to regional planning in competitive markets. This was due mainly to the historic vertical integration of the utility industry and the construction of legacy plants with transmission facilities to match the delivery of their output to the utility’s franchised load.
FERC made a major effort to stimulate regional construction of needed regional transmission capacity with Order 1000 in 2011, which required regional transmission planning for regional transmission organizations or RTOs and regional cooperation by utilities outside of RTOs. It also required stakeholder agreement for the needed regional transmission capacity increases, competitive solicitations to select the entities that would construct that capacity, and a general principle to allocate costs tied to the benefits received from the new transmission capacity.
Notwithstanding the goals of Order 1000, FERC recognized that very little regional transmission capacity was actually being built over the past 10 years.
While FERC recognized that it needed to rethink its decision and provide for methods that would accelerate construction of new regional transmission and also rethink generation interconnection procedures, including interconnection queues and network upgrade cost allocations, FERC indicated that it did not have a sufficient understanding of the obstacles or the solutions to propose a new rule to resolve the delays.
Therefore, in July 2021, FERC issued an “advanced notice of proposed rulemaking” or ANOPR that identified many of the problems and asked the market to comment on the problems and possible solutions. Since that time, FERC has received volumes of comments from the gamut of interested parties in the power markets, and it has held technical conferences on the issues as well.
This should lead to issuance of a “notice of proposed rulemaking” or NOPR containing the elements that the commission believes would provide a better approach to planning for new transmission capacity, selecting the entities to construct the capacity, streamline the completion of that construction as well as facilitate interconnection, and properly allocate the costs to those who are most likely to benefit from the new transmission capacity.
But even if FERC is able to issue a NOPR in the near term taking into account the results of the ANOPR proceeding, the NOPR will be subject to a period for comments by interested parties, followed by a final rule that could modify the NOPR proposals. And the various RTOs and independent utilities affected by a final rule would be given a period of time to modify their procedures before actually having to comply with the final rule.
Consequently, even if the new rule is issued and turns out to contain more appropriate mechanisms to facilitate construction of regional transmission capacity and interconnection construction, its impacts will not be felt in the near term.
In the meantime, individual projects, whether renewable, storage or other technology, are having to wait in line for interconnection studies to determine whether their interconnections will require “network updates” to the transmission grid.
Neither the new infrastructure initiative plan nor the FERC re-evaluation of the regional planning process will do anything to speed interconnection for projects that are currently in line or planning to file for interconnection in the near future.
The existing policies of the various RTOs and individual utilities that are not members of RTOs will remain in place until they choose to amend their procedures and file them at FERC and FERC reviews them.
However, nearly all of the RTOS and utilities unaffiliated with RTOS are moving to modify their interconnection procedures to weed out from the avalanche of interconnection requests projects that are not viable and avoid restudying projects and clusters of projects to determine the network upgrade requirements on their systems and in the region for the foreseeable future. This will be an ever evolving process.
It remains to be seen whether the efforts by FERC to revise the regional transmission planning process will eventually work their way into or alongside these interconnection modification efforts to speed up the entry of more carbon neutral projects into the transmission grid. The new transmission component of the infrastructure bill will be only a minor step toward the major transmission expansion required over the next decade to meet the rapidly expanding needs for a cleaner world.
It should be noted that since ERCOT is not part of the interstate grid, the expansion of the backbone transmission system in Texas to accommodate more carbon-neutral projects would be a matter for the Public Utility Commission of Texas and ERCOT, not FERC, to address. However, the financial support from the federal government extends to Texas power sector assets as well.