The time of waiting and hoping is over for taxpayers looking to finance and develop hydrogen projects. Treasury and the IRS issued enough guidance on Inflation Reduction Act tax credits this month to rival the length of The Count of Monte Cristo.
Readers who had to parse 379 pages of hydrogen rules — 306 of which are in the preamble — may be forgiven if they feel as badly done by as poor Edmond Dantès. But at least the government politely waited until January instead of ruining everyone’s holiday plans.
The final regulations under section 45V are an improvement over the proposed regulations, said Barbara de Marigny of Baker Botts. “The government has clearly worked hard to dig into the details, evaluate over 30,000 comments, and provide hydrogen industry participants with a degree of certainty that will allow them to evaluate their position under the regulations,” she said.
Beth Deane of Electric Hydrogen said the regs will “break the logjam that has been happening in the absence of final rules on section 45V” and should give rise to the first building wave of new projects, thus making the United States more competitive.
“We don’t want a repeat of solar, where the innovation happened here and China took the manufacturing to the next level,” she said. “Hydrogen is at the very beginning, so we have the opportunity to ensure manufacturing happens in the U.S. from the get-go.” She added that stakeholders’ general satisfaction with the final rules should also help their durability with the new administration.
What’s In and What’s Not
Let’s get the main disappointment for hydrogen industry participants out of the way first: One of the most requested items that was not adopted in the final rules is the general grandfathering for qualifying energy attribute certificates (EACs) for hydrogen projects that have a beginning-of-construction, placed in service, or commercial operations date before a specific date. The qualifying EAC rules in reg. section 1.45V-4(d)(2)(iii)(E) require hourly matching starting on January 1, 2030. The preamble explains that the government did not provide exemptions from or delay the application of the EAC requirements because doing so could lead to induced grid emissions. It says, “Delaying the qualifying EAC requirements would delay the entire regulatory framework that addresses the risk of significant indirect emissions and ensures that the credit is only awarded to hydrogen produced through a process that results in qualifying lifecycle [greenhouse gas]
emission rates, which would be in a manner that is contrary to the statute.”
More curiously, the rules don’t create an exception from the qualifying EAC requirements for hydrogen facilities that have a dedicated, co-located source of clean electricity. The statute contains no mention of EACs and thus has no incrementality, temporal matching, or deliverability requirements. The argument for permitting EACs comes from a Senate floor colloquy.
Instead, the text of section 45V seems to indicate that a hydrogen producer should have a solar facility, wind farm, or other clean energy facility next door. New co-located facilities should easily meet the incrementality, temporal matching, and deliverability requirements because the electricity they generate will be new and will go straight into the hydrogen facility.
But the preamble suggests that the EAC requirements are still needed because existing behind-the-meter sources could create induced emissions if they were previously connected to the grid or used for a purpose other than hydrogen production. The preamble explains that “the required use of the EAC framework described in the proposed regulations provides for a consistent and effective anti-double counting system that is uniform for all taxpayers, regardless of their sources of electricity, and represents standard industry practice across regulatory and voluntary markets.”
The three-pillars-for-all approach at least has the benefit of uniformity. The preamble says that behind-the-meter sources of clean electricity often already participate in EAC registries, which should make the transition fairly seamless for most. Some verification requirements would likely have been needed even if EACs were prohibited, so perhaps participating in an EAC registry won’t be too difficult for co-located facilities.
Now for the good news: The survival of the three pillars in the final regulations is offset by increased flexibility in the rules. The flexibility and certainty mean that taxpayers can pursue financing for projects and understand how the rules may affect their emissions rate, said Jenny Speck of Vinson & Elkins LLP.
She added that the final rules give clear guidance on the interplay of section 45V and other tax credits, and she clarified that a hydrogen facility can have other types of credit-eligible property, thus enabling taxpayers to structure different types of activities. “I think you’re going to see a lot of carbon capture projects implemented at similar locations to hydrogen facilities, but not directly related to the production of hydrogen,” Speck said.
Speck pointed out that the safe harbors in the final rules will also help taxpayers move ahead with hydrogen projects as they provide more certainty for a project’s economics. For example, a taxpayer who receives a provisional emissions rate before starting construction can rely upon the provisional emissions rate for their entire credit period under the final rules. Also, taxpayers can now submit a class 3 front-end engineering and design study as an indication of project maturity instead of a class 5 study, which means more taxpayers can apply for a provisional emissions rate sooner in their development process. The ability to rely on a provisional emissions rate obtained before the start of construction “is a huge win for companies that might be on the sidelines today that need financing,” Speck said.
The loosening of the incrementality, temporal matching, and deliverability requirements is good for the hydrogen industry. Two more years of reprieve are provided before hourly matching is required. That could mean a project wouldn’t need hourly matching for four or five years of its total life, said Matt Donnelly of Gibson, Dunn & Crutcher LLP. “That’s enough time for a lot of electricity generation projects to be completed and a step in the right direction,” he added. Donnelly said other changes, such as the addition of cross-region transmission when the deliverability can be tracked and verified, make the rules more commercially viable.
Because of their existing decarbonization standards and greenhouse gas cap programs, California and Washington are exempt from the incrementality requirement. Hydrogen facilities in those states — and any other states that end up qualifying — can satisfy that requirement by using qualifying EACs from existing clean electricity generators. Qualifying states are those with a qualifying electricity decarbonization standard and a qualifying greenhouse gas cap program.
The definitions are based in part on the standards and programs in California and Washington. “The exception to incrementality for states where the addition of renewable resources is legislatively mandated makes good sense,” said de Marigny. She said the requirements to become a qualifying state present a high hurdle, however, including a target of 100 percent of electricity from renewable resources by 2050.
The nuclear industry got a boost, particularly for plants nearing retirement, but also for facilities that are adding capacity. Nuclear power groups sought qualification for hydrogen produced with nuclear energy that came from a reactor that might otherwise retire, and the government responded. Electricity from certain existing reactors that meet the definition of a qualifying nuclear reactor will be considered incremental, and qualifying nuclear reactors may qualify for the section 45U credit too. However, only up to 200-megawatt hours of electricity per operating hour per qualifying nuclear reactor may be considered incremental. The government decided not to add criteria regarding relicensing to the qualifying nuclear facility definition.
The preamble noted that nuclear generators are the largest sources of clean electricity among individual reactors — meaning that a closure could result in large increases in emissions — and that nuclear plants have the “most demonstrably significant risk of retirement.” The definition of a qualifying nuclear reactor targets plants most at risk of retirement, which are merchant reactors and single-unit reactors, and it includes a financial test modeled on section 45U and a demonstration that the hydrogen facility is materially contributing to the continued operation of the at-risk reactor over the long term, either through a behind-the-meter connection or a long-term supply agreement between the reactor and the hydrogen facility.
The requirements for a qualifying nuclear reactor are a good proxy for retirement risk, said Jonathan Rund of the Nuclear Energy Institute. However, the section 45U guidance isn’t out yet, so the definition for average annual gross receipts necessary for the financial test also isn’t available, because the hydrogen rules cross-reference the rules for section 45U. Rund noted that section 45U took effect last year, and while the industry has taken reasonable positions on the meaning of gross receipts in that context, the diverse business models in the nuclear industry make it important to clarify how gross receipts are determined based on the different ways nuclear plants generate revenue.
The 200-megawatt-hours per hour limitation on electricity deemed incremental is based on commercial-scale electrolyzers. The preamble explains that allowing a hydrogen producer to purchase electricity beyond what is needed to substantially reduce the retirement risk of the reactor “would divert that electricity from other uses on the grid, requiring additional electricity generation with the substantial risk that it will be generated by emitting sources.”
Rund said that although the 200-megawatt-hours per hour limit could have been higher, it helps companies with near-term plans for supply and hydrogen producers. For nuclear facilities with two or more units with integrated operations, the 200-megawatt-hours per hour limit can be aggregated. That acknowledges the realities of reactor operations by providing flexibility when one unit is shut down for refueling for a few weeks, Rund said.
Nuclear reactors can also benefit from the modifications to the uprate rules, including a provision in reg. section 1.45V-4(d)(3)(i)(B)(2) that allows electricity generated from a restarted facility to be deemed incremental production. Rund said the uprate rule changes will help nuclear companies that want to make investments to increase capacity. And because the uprate rules are separate from the qualifying nuclear reactor rules, some existing plants might be able to combine the benefits of being a qualifying nuclear reactor with an increase in capacity.
Another big change in the final regulations is the addition in section 1.45V-4(f) of alternative fate assumptions for natural gas alternatives — biogas, renewable natural gas, and fugitive methane — and the elimination of the first productive use requirement. The assumptions were made in consultation with the Department of Energy and Environmental Protection Agency and “sought to apply the approach most appropriate for each type of source to provide an administrable and robust alternative fate for each sector,” according to the preamble.
The alternative fates are designed to address the emissions risks in lieu of the first productive use rule. The government chose not to apply venting as the all-purpose alternative fate, “because it does not account for the prevalence of flaring and productive use, nor does it address the risk of induced emissions due to the incentives provided by the section 45V credit,” and it would likely become less workable over time, according to the preamble.
The final rules also permit the use of a book-and-claim system for establishing claims to attributes of renewable natural gas or coal mine methane used in the production of hydrogen. “That is big, but buried in there is that you can’t use it before 2027,” de Marigny noted. Until then, taxpayers must have a direct pipeline connection between the gas source and the hydrogen facility in order to include the low-carbon nature of the gas in the hydrogen production’s emissions profile.
Administrative Procedure Act Compliance
The preamble explains that Treasury and the IRS “consulted extensively with scientific and technical experts from across the Federal government,” including Energy Department and EPA officials, in drafting the final rules. Essentially the same language appears in the final section 45Y and 48E regulations as well. Although reassuring and obviously reasonable, that might not be particularly helpful in a challenge because the delegations of authority simply require guidance “to carry out the purposes of this section, including regulations or other guidance for determining lifecycle greenhouse gas emissions.”
In their eagerness to provide taxpayer certainty, have Treasury and the IRS abandoned the position that their regulations are merely interpretive? In explaining the immediate effective date, the preamble says that “the final regulations provide needed rules on what the law requires for taxpayers to begin job-generating construction of capital-intensive projects qualifying for section 45V credits.” For many taxpayers hoping to claim one of those credits, obtaining project financing has been next to impossible without the certainty of final rules, but the preamble’s statement that the rules were necessary appears to be a concession.
The preamble notes that the IRS and Treasury considered necessary alternatives to the final rules. One example seems dubious: Officials “considered whether the production and sale or use of the hydrogen could be verified by an unrelated party without requiring the unrelated party to possess certain qualifications or conflict of interest characteristics,” and then, of course, they rejected the idea as an obvious opening for fraud and abuse. That appears 300 pages into the preamble, so the writers might simply have been exhausted by then, but examples of alternatives should probably be more serious than that. The other examples showed the government mulling over what are essentially administrative details.
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