Key Takeaways
- In May 2024, the Department of Energy identified 10 development regions that are eligible for up to $4.5 billion in federal funding for investments in transmission facilities.
- In the same month, the Federal Energy Regulatory Commission clarified its authority over states in some instances to streamline and control siting and permitting for transmission projects developed in those regions.
- The Commission is further requiring transmission providers to amend their tariffs to provide a methodology to identify and pay for long-term regional transmission facilities.
The country’s electric system is undergoing its most significant transformation in over a century. The information age is skyrocketing demand from customers for more power, and renewable energy is being deployed at a dizzying rate with solar power accounting for more than half of all new generating capacity in the country in 2023.
But new, clean generation capacity can’t reach power-hungry customers without high voltage power lines to carry it at distance. And the country’s existing transmission infrastructure is aged and feeble, causing frequent power outages during weather events when it is needed most. That is why recent announcements from the Department of Energy (DOE) to fund and support new transmission corridors and rulings from the Federal Energy Regulatory Commission (FERC or Commission) to reform long-term transmission planning will be critical for the ongoing transition to clean energy.
DOE: National Interest Electric Transmission Corridors
On May 8, 2024, DOE released a preliminary list of 10 potential “National Interest Electric Transmission Corridors” (Corridors) to accelerate the development of transmission projects in areas that present an urgent need for expanded transmission. Once finalized, development of new high voltage electricity lines in these areas can be financed by direct federal loans and be subject to FERC’s siting and permitting authority to block state interference and NIMBYism.
The Infrastructure Investment and Jobs Act (2021) (commonly referred to as the Bipartisan Infrastructure Law) amended the Federal Power Act to give DOE’s secretary, currently Jennifer Granholm, expanded authority to designate transmission Corridors. The Corridors are in areas DOE identified with present or expected transmission capacity constraints or congestion adversely affecting consumers. Once designated, $2 billion in federal funding is available to projects within Corridors in the form of direct loans under the Transmission Facility Financing (TFF) program authorized by the Inflation Reduction Act (2022). The May 8, 2024 announcement also provides minimum eligibility criteria for direct loans under the TFF program.
Transmission projects located in Corridors can also leverage up to $2.5 billion in federal funding under the Transmission Facilitation Program (TFP). The program authorizes DOE to co-own and build transmission facilities with a developer if the project is in a Corridor. TFP also authorizes DOE to enter capacity contracts with developers where the agency serves as an “anchor customer,” buying up to 50% of planned line rating for up to 40 years (and then selling the contract to recover costs). DOE is currently in its second round of requests for proposals under the TFP. The first round of proposals was already awarded to projects spanning the mountain west and desert southwest. Each project is intended, in part, to carry renewable energy such as wind power from rural areas to new customers.
Critically, in addition to public money, the Corridor designation also unlocks FERC’s siting and permitting authority pursuant to the Federal Power Act, as amended by the Bipartisan Infrastructure Law. FERC’s power takes primacy over states if they do not have state authority to site transmission or the state fails to act or denies an application to site transmission. FERC’s power also includes granting the transmission developer the ability to obtain rights-of-way through eminent domain. In that way, FERC can prevent states or landowners from blocking or sandbagging these critical grid upgrades.
According to DOE, the preliminary list of Corridors has the potential to facilitate the integration of renewable energy resources such as solar and wind, including offshore wind generation in the Atlantic Ocean. One of the designations — the Midwest-Plains Corridor — is a 780-mile corridor in parts of Illinois, Indiana, Kansas and Missouri and may increase interconnections to the systems managed by PJM, MISO and SPP.
DOE is currently seeking public comment on the preliminary list of Corridors. After the comment period closes June 24, 2024, DOE will conduct additional public engagement and prepare final designation reports and environmental documents, as needed.
FERC: Long-Term Regional Transmission Siting, Planning and Cost Allocation Reforms
On May 13, 2024 — only days after DOE’s Corridor announcement — FERC issued two transformative orders reforming long-term transmission siting, planning and cost allocation: Order Nos. 1977 and 1920.
Order No. 1977
Order No. 1977 amends FERC’s regulations to provide a backstop siting authority for DOE-designated Corridors and to conform with the amendments to the Federal Power Act in the Bipartisan Infrastructure Law. Specifically, Order No. 1977 clarifies that FERC has the authority to issue permits to construct or modify transmission facilities in a Corridor if a state has denied or delays an application. In addition, it establishes a Code of Conduct for applicants to demonstrate they have made good-faith efforts to engage with landowners and other stakeholders early in the permitting process.
FERC unanimously approved Order No. 1977, which follows from a Notice of Proposed Rulemaking (NOPR) issued in December 2022. Notably, the Commission declined to adopt the NOPR proposal to allow developers to simultaneously file state and federal transmission siting applications to expedite the federal permitting process. Instead, applicants must proceed with the state siting process and file applications with FERC only after the denial of their state process or a delay of over one year.
Order No. 1920
Order No. 1920 enacts major reforms to transmission planning requirements applicable to all transmission providers. This builds upon the Commission’s last major transmission reform initiative in Order No. 1000, which was issued in 2011.
It aims to encourage transmission owners to build transmission facilities efficiently and strategically and to avoid piecemeal transmission upgrades such as those required to serve one-off needs for a new large load or generator. This Final Rule will likely have the greatest impact in the Southeast and other regions that lack organized wholesale markets and independent transmission operators. Such areas are less likely to incentivize the long-term transmission planning envisioned by Order No. 1920.
FERC narrowly approved the Final Rule on a 2-1 party-line vote with the lone Republican Commissioner, Mark Christie, filing a spirited 77-page dissent that lays out a blueprint for an appeal. The Final Rule adopts many of the proposals contained in the notice of proposed rulemaking (NOPR) but makes modifications to several key proposals discussed below.
Long-Term Regional Transmission Planning
The Final Rule requires each transmission provider to engage in regional transmission planning to identify and evaluate long-term needs and select transmission facilities to best meet those identified needs. Transmission providers must prepare at least three distinct scenarios relying on different assumptions and sensitivities on (at least) a 20-year planning horizon. Plans must be reassessed and revised at least every five years.
Additionally, the order requires transmission providers to propose an evaluation process and selection criteria for purposes of regional transmission planning. While transmission providers are required to consult with relevant state entities, providers are not required to obtain the consent of these entities to the evaluation process and selection criteria.
The transmission provider’s planning process must consider and measure the following seven benefits of regional transmission facilities:
- Avoided or deferred reliability transmission facilities and aging infrastructure replacement,
- A benefit that can be characterized and measured as either reduced loss of load probability or reduced planning reserve margin,
- Production cost savings,
- Reduced transmission energy losses,
- Reduced congestion due to transmission outages,
- Mitigation of extreme weather events and unexpected system conditions, and
- Capacity cost benefits from reduced peak energy losses.
As part of this process, transmission providers must (1) identify one or more transmission facilities that addresses long-term needs with input from stakeholders, (2) estimate the costs and benefits of the facilities identified or proposed for potential selection, and (3) select or not select a project no later than three years following the beginning of the planning cycle. Note, however, there is no requirement that transmission providers select a long-term regional transmission facility even if it meets the approved selection criteria.
Consideration of Interconnection-Related Needs
Transmission providers must evaluate interconnection-related needs identified in existing generator interconnection processes, which have not yet been built. Specifically, the Final Rule requires transmission providers to consider some interconnection-related network upgrades that: (1) were identified in at least two interconnection queue cycles, (2) have a voltage of at least 200 kV and an estimated cost at least $30 million, and (3) have not been developed and are not currently planned to be developed.
Transmission providers must also implement a process to provide relevant state entities (e.g., the state’s regulator) and interconnection customers with the opportunity to voluntarily fund the cost of, or a portion of the cost of, a regional transmission facility that would not otherwise meet the transmission providers’ selection criteria. This voluntary funding mechanism is likely to increase the number of facilities selected during the regional planning process and give large energy users and renewable energy developers more control over transmission investments.
Transmission Cost Allocation and State Participation
Transmission providers must develop and file one or more cost allocation methods in their tariffs to apportion the costs from selected long-term regional transmission facilities. However, transmission providers and relevant state entities may propose a different cost allocation method before or within a defined period after the selection of transmission facilities. To implement this provision, the Final Rule requires transmission providers to notify relevant state entities and provide a forum for negotiation of a potential cost allocation method during a six-month period after the selection of transmission facilities. The Commission did not, however, adopt the NOPR proposal to mandate that the relevant state entities consent to the transmission provider’s cost allocation method. This portion of the order will likely be the subject of a legal challenge.
Unless the relevant state entities have otherwise agreed to the cost allocation method proposed by the transmission provider, all long-term regional transmission cost allocation methods must comply with the first five cost allocation principles set forth in FERC’s prior Order No. 1000. Consistent with these principles, transmission provides must ensure that the costs of selected transmission facilities are allocated in a transparent manner within the transmission region that is “roughly commensurate with estimated benefits.”
Finally, FERC declined to limit the availability of the Construction Work In Progress (CWIP) incentive for purposes of cost recovery. Transmission providers have relied upon the CWIP incentive to recover the costs of construction for transmission facilities before the facilities go into service. The Commission determined this incentive should be considered in a separate proceeding.
Local Transmission Planning Reforms and ‘Right-Sized’ Replacement Transmission Facilities
The Final Rule requires transmission providers in each planning region to implement reforms to enhance the transparency of local transmission planning information and obtain input from interested stakeholders. Among other things, transmission providers within each planning region must (1) publicly post information related to assumptions, needs and solutions considered during local transmission planning processes, and (2) establish an iterative process to allow stakeholders an opportunity to participate and provide feedback on local transmission planning, including three publicly noticed stakeholder meetings.
The reforms seek to address concerns that local transmission planning has not met expectations for openness, coordination and transparency. They are also intended to provide opportunities for increased stakeholder involvement and coordination with regional transmission planning.
In addition, transmission providers must evaluate whether transmission facilities operating above 200kV that the provider owns and anticipates replacing within 10 years may be “right-sized” to increase the facility’s transfer capability to meet current or future transmission needs. FERC also established a federal right of first refusal to facilitate the construction of a “right-sized” replacement transmission facility selected through the process. This will allow an incumbent utility to develop the selected transmission facility itself without opening development to a competitive bidding process, which has been required for certain projects by regional transmission organizations. The expansion of existing transmission facilities will provide a cost-effective and efficient mechanism to increase transmission capacity on the grid.
Next Steps and Anticipated Litigation
Order Nos. 1977 and 1920 become effective 60 days after publication in the Federal Register. Transmission providers must make the first initial compliance filings for Order No. 1920 within 10 months of the effective date of the Final Rule. Transmission providers must begin the first long-term regional planning cycle no later than one year from the date of initial filings to comply with Order No. 1920, unless the provider requests and obtains additional time to align pre-existing transmission planning cycles.
There will likely be legal challenges to Order No. 1920, particularly in light of the issues raised in Commissioner Christie’s dissent. The deadline for stakeholders to file a petition for rehearing for Order Nos. 1920 and 1977 is June 12, 2024. Rehearing requests are the first step in a lengthy process to appeal FERC orders to the federal courts. However, requests for rehearing and appeals will not stay FERC’s compliance processes unless the regulatory body or federal court orders otherwise.
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