Solar developers in the PJM region, particularly in Pennsylvania, West Virginia, and Ohio, often encounter land with a complex history of mineral development. This history can significantly impact solar projects, from site planning to obtaining title insurance coverage. Understanding the interplay between surface and subsurface rights is crucial for developers to protect their interests and ensure project viability. Diligent site planning and careful review of mineral title research can go a long way in preventing worst case scenarios and mitigating risk.

On June 14, 2024, the Nebraska Department of Transportation (“NDOT”) informed potential applicants that, pursuant to its National Electric Vehicle Infrastructure (“NEVI”) plan, applications for federal funding to build electric vehicle (“EV”) charging stations across Nebraska’s Interstate 80 will be available as early as August 2024. Nebraska is currently one of only 15 states yet to make this funding available to applicants. 

As detailed previously, the Inflation Reduction Act (IRA) offers incentives to renewable energy development that takes place on certain properties that are affected by potential or confirmed contamination. Under the IRA, a 10% adder is available to any investment tax credit (ITC) or production tax credit (PTC) generated by a renewable energy project constructed on a “brownfield site,” and there have been many questions since the IRA’s passage about what constitutes a brownfield site.

On June 13, 2024, the Federal Energy Regulatory Commission (FERC) issued an “Order to Show Cause”[1] (Order) under Section 206 of the Federal Power Act to four regional transmission organizations (RTOs) and independent system operators (ISOs). FERC is concerned that the RTOs/ISOs’ open access transmission tariffs (OATT) are unjust, unreasonable, and discriminatory because they allow transmission owners (TOs) to unilaterally elect “TO Initial Funding” (a funding mechanism that allows TOs to fund network upgrade capital costs upfront and then recover those costs from interconnection customers) which FERC believes may create barriers to interconnection and result in discrimination.

FERC is directing the Regional Transmission Operators (RTOs) and Independent System Operators (ISOs) to either show cause as to why their OATTs are just and reasonable or explain what changes they would make to remedy the concerns. The Order acknowledges and discusses the background of the issue, including FERC’s Order No. 2003, which established an interconnection pricing policy that allows RTOs/ISOs to propose alternative pricing mechanisms.

However, FERC is concerned about the potential for discrimination when the transmission provider is not independent. The Order further discusses the different ways that network upgrade costs can be funded in the Midcontinent Independent System Operator (MISO) region, recent case history related to TO Initial Funding, and a number of proceedings related to the issue. The Order also raises concerns about potential discrimination by transmission owners in PJM, Southwest Power Pool (SPP), and ISO New England, as well as questions about whether transmission owners face any uncompensated risks associated with owning, operating, and maintaining network upgrades.

FERC requests the RTOs/ISOs to address these concerns and answer a number of questions related to increased costs and potential discrimination.  Under its Section 206 authority, FERC directs each of the four RTOs/ISOs, within 90 days of the date of the Order (i.e., Wednesday, September 11, 2024), either: (1) to show cause as to why its OATT remains just and reasonable and not unduly discriminatory or preferential and provide responses to the questions set forth in the Order; or (2) to explain what changes to its OATT it believes would remedy the identified concerns if the commission does determine the self funding to be unjust and unreasonable.

The impact of “TO self funding” on generation developers can be substantial. Here is a breakdown of the potential impacts on generation developers:

  • Increased Costs: When transmission owners can pass on the upfront capital costs of network upgrades to generation developers, it significantly increases the cost of connecting to the grid, impacting the financial viability of new generation projects.
  • Barrier to Entry: These additional costs serve as a barrier to entry, particularly for smaller developers or those with more innovative or less capital-intensive technology, impacting resource diversity and competitiveness of the market.
  • Project Delays: Disputes over cost allocations and the process of funding network upgrades lead to project delays, harming generation developers who rely on predictable timelines to plan and execute their projects and secure financing.
  • Financing Challenges: The uncertainty and potential for increased costs associated with network upgrades make it more difficult for generation developers to secure financing, as lenders and investors may see the projects as riskier investments.
  • Operational Risks: Questions raised by FERC about whether transmission owners face any uncompensated risks associated with owning, operating, and maintaining network upgrades might affect terms and conditions of interconnections, potentially passing more risks onto generation developers.
  • Discrimination Concerns: The potential for discriminatory practices by transmission owners could undermine the fair and competitive access to the grid for new generation developers, potentially favoring incumbent players or certain types of generation.

The FERC directive for RTO/ISOs to either justify the fairness of these practices or propose changes is therefore very significant for generation developers, who stand to benefit if the costs and risks associated with network upgrades are distributed more equitably and transparently.

For more information about the Order’s potential impact on your specific situation or to explore the next steps in light of the Order, please contact Michael Blackwell or a member of Husch Blackwell’s Energy Regulation team.

[1] Midcontinent Indep. Sys. Operator, Inc., et al., 187 FERC ¶ 61,170 (2024) (FERC Docket Nos. EL24-80-000, EL24-81-000, EL24-82-000, EL24-83-000).

Last month, Husch Blackwell published its seventh-annual report on public-private partnerships (P3s) and alternative project delivery strategies. This year’s report features an interesting article by Michael Blackwell, an attorney on the firm’s Energy & Natural Resources team, that explores how P3s and P3-like agreements might be deployed to hasten the transition from fossil fuels…

At its May 13, 2024 open meeting the Federal Energy Regulatory Commission (FERC) unanimously approved Order No. 1977,[1] which updates the process FERC uses when exercising its transmission siting authority under Section 216 of the Federal Power Act, as amended by the Infrastructure Investment and Jobs Act of 2021 (IIJA). 

At its May 13, 2024 open meeting, the Federal Energy Regulatory Commission (FERC) approved a groundbreaking final rule—Order No. 1920[1] —requiring public utilities to undertake new long-term regional transmission planning over a 20-year horizon and allocate the cost of selected transmission projects in a manner that corresponds to the benefits they provide. 

On May 29, 2024, the U.S. Treasury Department and the Internal Revenue Service issued a notice of proposed rulemaking (“NPRM”) that includes guidance on two of the Inflation Reduction Act of 2022’s renewable electricity tax credits – but which notably failed to provide guidance with respect to the eligibility of clean electricity generated by biogas or renewable natural gas (“RNG”) for those credits, leaving RNG developers with lingering questions.