Category: Energy Law

Good News for Offshore Wind Blows in With New Guidance From the Treasury and IRS

The Inflation Reduction Act of 2022 (IRA) includes several tax credits to encourage investment in renewable energy projects, including an Investment Tax Credit (ITC) that is worth up to 30% of the overall project cost. The developer of a renewable energy project can receive a bonus of up to 10% on top of the ITC for a qualified facility that is located or placed in service in an “energy community.” One type of area that can qualify as an energy community under the IRA — the one most relevant to offshore wind projects — is an area that has significant employment or local tax revenues from fossil fuels and a higher-than-average unemployment rate.

In order to apply the criteria to offshore wind facilities, the US Department of Treasury initially proposed that an offshore wind project would be deemed to be located or placed in service at the place closest to the point of interconnection (POI) where there is land-based equipment that conditions the energy generated by the offshore wind project for transmission, distribution, or use.

Stakeholders in the offshore wind industry believed, however, that this approach did not adequately reflect the original intent of the IRA as it neglected to take into account the long-term benefits of activity related to offshore wind projects at locations, particularly ports, that were not at the POI.

Responding to stakeholder advocacy over the past several months, on March 22, the Internal Revenue Service (IRS) released updated guidance in IRS Notice 2024-30 (the Notice). The Notice permits projects with multiple POIs to qualify for the bonus credit, so long as one of the POIs is within an energy community. Stakeholders believe that this will be key in developing the shared transmission infrastructure that will be required for effective use of offshore wind energy.

Further, the Notice permits offshore wind facilities to attribute their nameplate capacity to additional property — namely, to supervisory control and data acquisition system (SCADA) equipment owned by the owner of the offshore wind project and located in an EC Project Port (as defined in the Notice). SCADA equipment is property that is used to remotely monitor and control the operations of the offshore wind project. The SCADA system is effectively the nerve center for an offshore wind project.

An “EC Project Port” is defined in the Notice as a port that is used either full or part time to facilitate maritime operations necessary for the installation or operation and maintenance of the offshore wind project, and that has a significant long-term relationship with the project’s owner by virtue of ownership or lease arrangements. The personnel based at the port need to include staff who are employed by, or who work as independent contractors for, the project’s owner and who perform functions essential to the project’s operations. Staff based at the port will be considered to perform functions essential to the project’s operations only if they collectively perform all the following functions: management of marine operations, inventory and handling of spare parts and consumables, and berthing and dispatch of operation and maintenance vessels and associated crews and technicians.

Finally, the Notice adds two industry codes from the North American Industry Classification System (NAICS) to those that are used to determine a community meets the IRA’s required percentage of its workforce who are employed in the extraction, processing, transport, or storage of coal, oil, or natural gas. These additional NAICS codes designate oil pipeline infrastructure and natural gas distribution infrastructure. These additional codes are intended to bring the benefits of the energy community bonus credit to more communities and the IRS has amended its list of energy communities accordingly.

Advocates note that the updated guidance in the Notice represents a more holistic approach to the energy communities bonus credit that will give offshore wind project developers more flexibility in identifying ports for their investment, The increased flexibility will bring the economic benefit of the offshore wind industry to more communities, which will ultimately reduce the cost burden to ratepayers.

© 2024 Jones Walker LLP
For more news on Tax Credits for Renewable Energy, visit the NLR Tax section.

President Biden Nominates Three FERC Commissioners

On February 29, 2024, President Biden nominated three new commissioners of the Federal Energy Regulatory Commission (“FERC”). The nominations will be reviewed and voted on by the Senate Energy and Natural Resources Committee and are subject to confirmation by the full Senate. If approved, the nominees will provide FERC with a full slate of five commissioners, including three Democrats and two Republicans.

Judy Chang is the Managing Principal of the Analysis Group in Boston and former Undersecretary of Energy and Climate Solutions of the Massachusetts Department of Energy Resources. She is a Democrat and will succeed Commissioner Allison Clements with a term ending June 30, 2029. Commissioner Clements has announced that she would not serve a second term, but she may remain on FERC after June 30, 2024, until replaced or through December 31, 2024. Ms. Chang was the keynote speaker at Pierce Atwood’s 2022 Energy Infrastructure Symposium.

Lindsay See is the Solicitor General of the State of West Virginia. Ms. See is a Republican, recommended to the President by Senate Minority Leader Mitch McConnell, and will succeed former Commissioner James Danly with a term ending June 30, 2028. Ms. See has represented West Virginia in many multi-state legal coalitions on a variety of national issues, including energy and environmental rules and policies.

David Rosner is a member of the FERC staff, an energy industry analyst who has been on loan to the majority staff of the Senate Energy and Natural Resources Committee, which is chaired by Senator Joe Manchin of West Virginia. Mr. Rosner will succeed former Chairman Richard Glick with a term ending June 30, 2027.

All three nominations have been received by the Senate and referred to the Energy and Natural Resources Committee, which will hold a hearing on each nominee. The Committee has not yet scheduled any hearings.

FERC Chairman Willie L. Phillips was designated as chairman on February 9, 2024. He was previously acting chairman. His term ends June 30, 2026. Commissioner Mark C. Christie’s term ends on June 30, 2025.

©2024 Pierce Atwood LLP. All rights reserved.

Striking a Balance: The Supreme Court and the Future of Chevron Deference

In its frequent attempts to enforce the separation of powers that the Constitution’s framers devised as a system of checks and balances among the executive, legislative, and judicial branches of the federal government, it is often the so-called “Fourth Branch”—that includes the varied administrative agencies—that is at the heart of things.[1]

These agencies possess a level of technical and scientific expertise that the federal courts generally lack. And, without reference to expertise, Congress often leaves it to agencies and the courts to interpret and apply statutes left intentionally vague or ambiguous as the product of the legislative compromise required to gain passage. This phenomenon begs the question of the extent to which the federal courts may defer to administrative agencies in interpreting such statutes, or whether such deference abnegates the judicial prerogative of saying what the law is. Having passed on several opportunities to revisit this question, the Supreme Court of the United States has finally done so.

In what potentially will lead to a decision that might substantially change the face of federal administrative law generally while voiding an untold number of agency regulations, the Supreme Court, on January 17, 2024, heard oral argument in a pair of appeals, Loper Bright Enterprises, et al., v. Raimondo, No. 22-451, and Relentless, Inc., et al. v. Department of Commerce, No. 22-1219, focusing on whether the Court should overrule or limit its seminal decision in Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc., 467 U.S. 837 (1984).

Almost 40 years ago, the Chevron decision articulated the doctrine commonly known as “Chevron deference,” which involves a two-part test for determining when a judicial determination must be deferential to the interpretation of a statute. The first element requires determining what Congress has spoken directly to the specific issue in question, and the second is “whether the agency’s answer is based on a permissible construction of the statute.”

Among the most cited Supreme Court cases, Chevron has become increasingly controversial, especially within the conservative wing of the Court, with several Justices having suggested that the doctrine has led to the usurpation of the essential function of the judiciary.

Chevron deference affects a wide range of federal regulations, and the Court’s ruling, whether or not Chevron is retained in some form, is likely to result in significant changes to how agencies may implement statutes and how parties affected by regulations may seek relief from the impact of those regulations. Interestingly, commentators on the recent oral argument in the case are widely divided in their predictions as to the outcome—some suggesting that the conservative majority of the Court will overrule Chevron outright, others suggesting that the Court has no intention at all to do so.

Based on remarks made during the oral arguments by Justice Gorsuch, and by Justices Amy Coney Barrett and Elena Kagan, as well as Justice Kagan’s fashioning of a majority that clarified a related interpretive rule in an earlier case focusing on agencies’ authority to interpret their own regulations, we suggest that there is a substantial possibility that the Court will take a moderate path by strengthening judicial scrutiny at the “Step One” level while recognizing that there are technical and scientific matters as to which courts have no expertise. At the same time, the Court may make it clear that, essentially, legal issues are within its prerogatives and are not subject to agency interpretation.

We examine how the Court might find a path to a better balancing of agency and judicial functions that is consistent with and builds upon other recent rulings involving the review of actions taken by administrative agencies. Whatever the outcome, the Court’s ruling in these cases will have a profound impact on individuals and entities that are regulated by federal agencies or that depend on participation in government programs, such as Medicare and Social Security.

A Chevron Refresher

Most law students and lawyers have some familiarity with the touchstone for judicial review of agency rules that was articulated in Chevron, a case that dealt with regulations published by the Environmental Protection Agency to implement a part of the Clean Air Act.[2] The Supreme Court explained that judicial review of an agency’s final rule should be based on the two-part inquiry that we mentioned earlier. First, the reviewing court should determine whether Congress made its intent unambiguously clear in the text of the statute; if so, the inquiry ends, and both the agency and the reviewing court must give effect to Congress’s intent. This has become known by the shorthand phrase “Step One.”

If Congress’s intent is not clear, either because it did not address a specific point or used ambiguous language, then the court should defer to the agency’s construction if it is based on a permissible reading of the underlying statute. This has become known as “Step Two.”

In applying Step Two, a reviewing court should determine if the gap left by Congress was explicit or implicit. If the ambiguity is explicit, then the agency’s regulations should be upheld unless they are arbitrary, capricious, or contrary to the statute.[3] If the ambiguity is implicit, then the “court may not substitute its own construction of a statutory provision for a reasonable interpretation made by the administrator of an agency.”[4]

Chevron deference is not a blank slate for courts to find ambiguity. It recognized that the judiciary “is the final authority on issues of statutory construction” and instructed that in applying Step One, judges are expected to apply the “traditional tools of statutory construction.”[5] It also recognized that any deference analysis should fit within the balance among the branches of government. The Supreme Court explained that while Congress sets an overall policy, it may not reach specific details in explaining how that policy is to be executed in particular contexts. In these situations, the executive branch may have the necessary technical expertise to fill in the details, as it is charged with administering the policy enacted into law. The Court noted that the judiciary was not the ideal entity to fill in any gaps left in legislation because “[j]udges are not experts in the field” and that courts are not political entities. As a result, agencies with expertise are better suited to carry out those policies. Moreover, even if agencies are not accountable to the public, they are part of the executive branch headed by the President, who (unlike judges with life tenure) is directly accountable to the electorate.[6]

Nevertheless, during the recent oral arguments, the Chief Justice stated that the Court had not in recent years employed Chevron itself in its analysis of agency action. The reason why the issue of whether Chevron unduly intrudes upon the judicial function, and whether it should be overruled or modified, relates to the fact that it is widely used in lower court review of administrative actions. Its reconsideration also relates to increasing jurisprudential conservatism on the Supreme Court and the application of originalism and, more widely, textualism.

The Chevron concept of deference to agency regulations exists alongside a line of cases in which courts have deferred to an agency’s interpretations of its own regulations. In both Bowles v. Seminole Rock & Sand Co.[7] and Auer v. Robbins,[8] the Supreme Court developed the principle that courts are not supposed to substitute their preference for how a regulation should be interpreted; instead, a court should give “controlling weight” to that interpretation unless it is “plainly erroneous or inconsistent with the regulation.”[9] Nevertheless, the Court has refused to extend that form of deference to subregulatory guidelines and manuals where there is little or no evidence of a formal process intended to implement Congress’s expressed intent.[10]

The Chevron framework has generated criticism, including statements by several current Justices. Their position relies on an argument that Chevron distorts the balance of authority in favor of the executive and strips courts of their proper role. In a recent dissent from a denial of certiorari, Justice Gorsuch complained that Chevron creates a bias in favor of the federal government and that instead of having a neutral judge determine rights and responsibilities, “we outsource our interpretive responsibilities. Rather than say what the law is, we tell those who come before us to go ask a bureaucrat.”[11] Justice Thomas has written that the Administrative Procedure Act does not require deference to agency determinations and raises constitutional concerns because it undercuts the “obligation to provide a judicial check on the other branches, and it subjects regulated parties to precisely the abuses that the Framers sought to prevent.”[12]

Chevron and the Herring Fishermen

The dispute that has brought Chevron deference to the Supreme Court in 2024 starts with the business of commercial fishing for herring. The National Marine Fisheries Service (NMFS) published a regulation in 2020 that requires operators of certain fishing vessels to pay the cost of observers who work on board those vessels to ensure compliance with that agency’s rules under the Magnuson-Stevens Fishery Conservation and Management Act of 1976 (“Act”). Several commercial fishing operators challenged the regulations, which led to two decisions by the U.S. Courts of Appeals for the District of Columbia Circuit and the First Circuit. Both courts upheld the regulations, but on slightly different grounds. In the first decision, Loper Bright Enterprises, Inc. v. Raimondo,[13] the District of Columbia Circuit followed the traditional Chevron analysis and concluded that the Act did not expressly address who would bear the cost of the monitors. The NMFS’s interpretation of the statute in the regulation was found to be reasonable under Step Two of Chevron based on the finding that the agency was acting within the scope of a broad delegation of authority to the agency to further the Act’s conservation and management goals, and on the established precedent concluding that the cost of compliance with a regulation is typically borne by the regulated party.

The second decision by the First Circuit, Relentless, Inc. v. United States Department of Commerce,[14] took a slightly different approach. That court focused on the text of the Act and concluded that the agency’s interpretation was permissible. It did not anchor its decision in a Chevron analysis and stated that “[w]e need not decide whether we classify this conclusion as a product of Chevron step one or step two.”[15] The First Circuit also emphasized that the operators’ arguments did not overcome the presumption that regulated entities must bear the cost of compliance with a relevant statute or regulation.

The parties have staked out starkly different views of Chevron’s legitimacy and whether it is compatible with the separation of powers in the U.S. Constitution. The fishermen petitioners argue that Chevron is not entitled to respect as precedent because the two-part test was only an interpretive methodology and not the holding construing the Clean Air Act. Their core argument is that Chevron improperly and unconstitutionally shifts power to the executive branch by giving more weight to the agencies in rulemaking and in resolving disputes where the agency is a party and shifts power away from the judiciary’s role under Article III to interpret laws and Congress’s legislative authority power under Article I. Taking this one step further, the petitioners argue that this shift violates the due process rights of regulated parties. They also argue that Chevron is unworkable in practice, citing instances where the Supreme Court itself has declined to apply the two-part test and the lack of a consensus as to when a statute is clear or ambiguous, making the application of Chevron inconsistent. Put another way, according to the petitioners, the problem with Chevron is that there is no clear rule spelling out how much ambiguity is needed to trigger deference to an agency’s rule. Next, they argue that Chevron cannot be applied when an underlying statute is silent because this allows agencies to legislate when there is a doubt as to whether Congress delegated that power to the agency at all and that it would run counter to accepted principles of construction that silence can be construed to be a grant of power to an agency. Finally, they contend that Chevron deference to agencies conflicts with Section 706 of the Administrative Procedure Act, where Congress authorized courts to “decide all relevant questions of law, interpret constitutional and statutory provisions, and determine the meaning or applicability of the terms of an agency action.”[16]

The Secretary of Commerce argues that there are multiple reasons to preserve Chevron deference. First, the Secretary argues that Chevron fits within the balance of power between the branches of the federal government. In the Secretary’s view, Chevron deference is consistent with the separation of powers doctrine, as it respects (1) Congress’s authority to legislate and to delegate authority to an administrative agency, (2) the agency’s application of its expertise in areas that may be complex, and (3) the judiciary’s authority to resolve disputed questions of law. Therefore, the Chevron framework avoids situations where courts may function like super-legislatures in deciding how a statute should be implemented or administered and second-guess policy decisions.

According to the Secretary, courts know how to apply the traditional tools of statutory interpretation, and if an ambiguity exists after that exercise is complete, it is appropriate to defer to an administrative agency that has technical or scientific experience with the subject matter being regulated. In addition, the Secretary contends that Chevron promotes consistency in the administration of statutes and avoids a patchwork of court rulings that may make it difficult or impossible to administer a nationwide program, such as Social Security or Medicare. Third, the Secretary notes that Chevron is a doctrine that has been workable for 40 years and that over those decades, Congress has not altered or overridden its holding, even as it has enacted thousands of statutes since 1984 that either require rulemaking or have gaps that have been filled by rulemaking. As a result, the Secretary argues that there are settled interpretations that agencies and regulated parties rely on, and overruling Chevron would lead to instability and relitigating settled cases. Finally, the Secretary argues that Chevron deference cannot be limited to interpretations of ambiguous language alone, as there are no accepted criteria for distinguishing ambiguous statutory language from statutory silence.

The Oral Argument

The Supreme Court heard arguments in both cases on January 17, 2024. Over more than three hours of argument, the Justices focused on several questions. Justices Kagan, Sotomayor, and Jackson expressed concerns that abandoning the Chevron framework would put courts in the position of making policy rather than just ruling on questions of law. In their view, courts lack the skills and expertise to craft policy and should not act as super-legislators. They also stressed that there are situations in which the tools of statutory construction do not yield a single answer or that Congress has not addressed the question either because it left some matters unresolved in the statute or through other subsequent changes not contemplated by Congress, such as the adoption of new technologies. In these cases, the Justices wanted to know why deference to an agency was not appropriate and did not see any clear indication that Congress intended that courts, not agencies, should make determinations when the statutory language is ambiguous or silent. They also questioned why the Supreme Court should overrule Chevron when Congress has been fully aware of the decision for 40 years and has not enacted legislation to eliminate the ability of a court to defer to an agency’s determinations.

The members of the more conservative wing of the Supreme Court questioned counsel about weaknesses in the Chevron framework. Justice Gorsuch returned to his earlier criticism of Chevron and asked the parties to define what constitutes enough ambiguity to allow a court to move from Step One to Step Two. He further questioned whether there was sufficient evidence that Congress ever intended to give the government the benefit of the doubt when an individual or regulated entity challenges agency action. Justice Gorsuch, along with Justices Thomas and Kavanaugh, asked whether Chevron actually resulted in greater instability and whether it was appropriate to abandon Chevron in favor of the lesser form of deference articulated in Skidmore v. Swift & Co., where deference is not a default outcome and a court is supposed to exercise its independent judgment to give weight to agency determinations based on factors including the thoroughness of the agency’s analysis, the consistency and validity of the agency’s position, and the agency’s “consistency with earlier and later pronouncements, and all those factors which give it power to persuade.”[17] The follow-up questions asked whether it was correct to accord deference to agency regulations when the agency’s policy can shift from administration to administration.

Where Is the Conservative Court Likely to Go?

The length of the argument and the alacrity of questioning do not mean that the Supreme Court is going to overrule the 40-year-old, highly influential Chevron doctrine. It is, however, quite likely that the doctrine will be narrowed and clarified. To say nothing of the recent oral argument, several recent decisions evidence a reluctance to abandon deference altogether. In a pair of decisions issued in 2022 involving Medicare reimbursement to hospitals, the Court resolved deference questions by relying on the statutory text alone.

Those decisions involved challenges to a Medicare regulation governing hospital reimbursement, and a published interpretation of a section of the Medicare statute governing reimbursement for outpatient drugs. Although the Court ruled in the government’s favor in the former case and against the government in the latter case, neither decision relies on Chevron—even though in one case, the petitioner’s counsel expressly asked the Court to overrule Chevron during the oral argument.[18] Yet, by relying on the text of each statute to resolve a regulatory dispute, the Court’s reasoning in both decisions is consistent with Step One of the Chevron test and demonstrates that it is workable in practice and need not result in a dilution of judicial review. In addition, the Court has developed another limit to agency action in its decisions, finding that when a regulatory issue presents a “major question,” deference is irrelevant unless the agency can show that Congress expressed a clear intent that the agency exercise its regulatory authority. This concept remains a work in progress because the Court has not defined criteria that make an issue a major question.[19]

These cases provide a useful background to an increasingly jurisprudentially conservative, textually oriented Court. Two cases that were specifically discussed during oral argument are particularly significant in plotting the Court’s landing place with regard to Chevron. Justice Gorsuch made multiple references to Skidmore, which sets forth the principle that a federal agency’s determination is entitled to judicial respect if the determination is authorized by statute and made based on the agency’s experience and informed judgment. Unlike the Chevron standard, the Skidmore standard considers an agency’s consistency in interpreting a law it administers.

The second, and more recent, precedent that is even more likely to guide the narrowing of Chevron is Kisor v. Wilkie.[20] There, a 5-4 divided Court adopted a multi-stage regime for reviewing an agency’s reliance upon arguably ambiguous regulations that is roughly analogous to Chevron’s two-stage analytical modality. In doing so, it modified, but did not overrule, Auer v. Robbins, 519 U.S. 452 (1997), and its doctrinal predecessor, Bowles v. Seminole Rock & Sand Co., 325 U.S. 410 (1945), which permit a court to defer to an agency’s interpretation of its own ambiguous regulation, so long as that interpretation is reasonable, even if the court believes another reasonable reading of the regulation is the better reading.

Kisor saw a mixed bag of Justices joining, or dissenting from, various parts of the Kagan opinion. What made the majority as to its operative section was the Chief Justice’s joining Justice Ginsburg, Breyer, and Sotomayor. With Justice Ginsburg having been succeeded by Justice Barrett, and Justice Breyer having been succeeded by Justice Jackson, one might hypothesize that there now would be a conservative 5-4 majority that would have overruled Auer. However, it was Justice Barrett who raised the possibility of “Kisorizing” Chevron, a suggestion quickly adopted by Justice Kagan. Justice Gorsuch, a longtime opponent of Chevron, is likely amenable to a Skidmore-oriented result.

The Kagan opinion cabins and arguably lowers the level of deference an agency’s interpretation of a rule should receive. Thus, with a strong nod to the Court’s jurisprudential drift to the right, Justice Kagan begins with the truism that whatever discretion an agency might claim, the Court’s analysis must proceed under the proposition that an unambiguous rule must be applied precisely as its text is written. It is not unlikely that, if the Court narrows Chevron (as we predict it shall), it also will begin with a more robust requirement to apply the statutory text in Step One and re-emphasize the need to exhaust all of the tools of statutory construction; in other words, there is no need for deference unless there is genuine ambiguity. If an agency’s determination is to become relevant, it only becomes so after ambiguity is established.[21]

In short, if the law gives a definitive answer on its face, there is nothing to which a court should defer, even if the agency argues that there is an interpretation that produces a better, more reasonable result. This is a textual determination that addresses the criticism of the so-called Administrative State’s acting as a quasi-legislature to which the Court yields its own power to say what the law is.

However, even a reasonable agency interpretation, the Kagan opinion notes, might not be dispositive. The opinion must be the agency’s official position, not one ginned up for litigation purposes, and it must reflect the agency’s particular expertise.

­Conclusion

In its 40-year life, Chevron deference has been at the heart of the application of federal administrative law. No case among all of the many governmental functions that the Supreme Court considers has been more widely cited, and no administrative law case has been more controversial, especially among jurisprudential conservatives. While asked by various parties to do so, the Court has declined, and the Chevron structure has been applied, often inconsistently, by federal courts. Perhaps reflecting the increasingly conservative direction of the Court, we have reached a point where the Court will consider retiring this long-standing precedent or, alternatively, refreshing it based on the experience of courts and agencies since 1984.

Justice Kagan’s analytic method in Kisor v. Wilkie could also apply to tightening Chevron. In her decisions, she has exhibited great fidelity to reading text literally, avoiding the perils of legislation from the bench. As she wrote in Kisor:

[B]efore concluding that a rule is genuinely ambiguous, a court must exhaust all the traditional tools of construction. . . . For again, only when that legal toolkit is empty and the interpretive question still has no single right answer can a judge conclude that it is more one of policy than of law. That means a court cannot wave the ambiguity flag just because it found the regulation impenetrable on first read. Agency regulations can sometimes make the eyes glaze over. But hard interpretive conundrums, even relating to complex rules, can often be solved. A regulation is not ambiguous merely because discerning the only possible interpretation requires a taxing inquiry. To make that effort, a court must carefully consider the text, structure, history, and purpose of a regulation, in all the ways it would if it had no agency to fall back on. . . . Doing so will resolve many seeming ambiguities out of the box, without resort to . . . deference” (citations and internal punctuation omitted).[22]

Text alone might not provide the answer in every case, as Justice Kagan recognizes as she outlines four additional steps that might lead to judicial deference to agency statutory interpretations. However, to the extent that a majority of the Court elects to retain Chevron, though narrowing it, her approach in the analogous setting reflected in Kisor would be effective in resolving the two cases now at bar—recognizing agency expertise in technical and scientific matters beyond the competency of the judiciary while preserving the function of the courts to determine what the legislature actually wrote, not to write it themselves.

* * * *

ENDNOTES

[1] Besides the administrative bureaucracy, various jurists and commentators have, under this rubric, included the press, the people acting through grand juries, and interest or pressure groups. Those institutions represent the arguable influence of extra-governmental sources. We are focused here on the level of judicial deference afforded to federal administrative agencies.

[2] 467 U.S. at 842-43.

[3] 5 U.S.C. § 706(2)(A).

[4] Id. at 844.

[5] Id. at 843, fn.9.

[6] Id. at 865-66.

[7] 325 U.S. 410, 414 (1945).

[8] 519 U.S. 452, 461 (1997).

[9] Id.

[10] United States v. Mead Corp., 533 U.S. 218, 229 (2001); Christensen v. Harris County, 529 U.S. 576 (2000).

[11] Buffington v. McDonough, No. 21-972 (Gorsuch, J., dissenting at 9) (2022).

[12] Perez v. Mortgage Bankers Ass’n, 135 S.Ct. 1199,1213 (2015) (Thomas, J., concurring in the judgment).

[13] 45 F.4th 359 (D.C. Cir. 2022).

[14] 62 F.4th 621 (1st Cir. 2023).

[15] Id. at 634.

[16] 5 U.S.C. § 706.

[17] 323 U.S. 134, 140 (1944).

[18] Becerra v. Empire Health Foundation, 142 S.Ct. 2354 (2022), and American Hospital Ass’n v. Becerra, 142 S.Ct. 1896 (2022). The request to overrule Chevron appears in the transcript of the American Hospital Ass’n oral argument, at 30.

[19] West Virginia v. EPA, 142 S.Ct. 2587 (2022); Utility Air Regulatory Group v. EPA, 573 U.S. 302, 324 (2014).

[20] 139 S. Ct. 2400 (2019).

[21] Kisor predicated deference, if at all, upon five preliminary stages. First, as noted, the reviewing court should determine that a genuine ambiguity exists after applying all of the tools of statutory construction. This is consistent with Step One of Chevron, but Justice Kagan makes it clear that this is a heightened textual barrier. Second, the agency’s construction of the regulation must be “reasonable”; this is a restatement of Step Two of Chevron. The Court cautioned that an agency can fail at this step. Third, the agency’s construction must be “the agency’s ‘authoritative’ or ‘official position,’” which was explained as an interpretation that is authorized by the agency’s head or those in a position to formulate authoritative policy. Fourth, the regulatory interpretation must implicate the agency’s “substantive expertise.” Finally, the regulatory interpretation must reflect the agency’s “fair and considered judgment” and that a court should decline to defer to a merely “convenient litigating position” or “post hoc rationalizatio[n] advanced” to “defend past agency action against attack.”

[22] 139 S.Ct. at 2415.

©2024 Epstein Becker & Green, P.C. All rights reserved.
For more news on Energy and the Environment, visit the NLR Environmental, Energy & Resources section.

Oil Pollution Act: Tips for Spill Response, Compliance, and Enforcement

Oil spills commonly occur when least expected and, even in smaller quantities can significantly disrupt business operations and create risks for enforcement and/or litigation. It’s important that companies are prepared and know the environmental requirements for when the least expected happens, including understanding what actually is “oil” (hint: it’s broader than you might think!), who to notify, legal authorities at play, and best practices to ensure compliance and minimize exposure to regulators and/or private parties.

What is “Oil” Anyway?

Section 311 of the Clean Water Act (CWA) and the Oil Pollution Act (OPA) make up the federal statutory framework for oil spills. However, many companies may not realize that both petroleum-based and non-petroleum-based substances are regulated as “oil” under the CWA and OPA. As a result, many companies may not realize that they are subject to these laws and, therefore, fail to adequately prepare for compliance and/or response both pre- and post-spill.

Specifically, Section 311(a)(1) of the CWA defines oil as “oil of any kind or in any form, including, but not limited to, petroleum, fuel oil, sludge, oil refuse, and oil mixed with wastes other than dredged spoil.” 40 CFR § 112.2 further defines oil as “oil of any kind or in any form, including, but not limited to: fats, oils, or greases of animal, fish, or marine mammal origin; vegetable oils, including oils from seeds, nuts, fruits, or kernels; and, other oils and greases, including petroleum, fuel oil, sludge, synthetic oils, mineral oils, oil refuse, or oil mixed with wastes other than dredged spoil.” This definition is notably broader than what many may consider “oil” (i.e., crude oil and refined petroleum products) and encompasses animal fats, vegetable oils, and non-petroleum oils.

When to Notify?

The CWA and OPA require companies to notify the National Response Center (NRC) of oil spills as soon as they are discovered (i.e., within 15 minutes). This applies to all discharges that reach navigable waters of the U.S. (WOTUS) or adjoining shorelines and (1) cause a sheen; (2) violate applicable water quality standards; or (3) cause a sludge or emulsion beneath the surface of the water or upon adjoining shorelines. In practice, this typically results from a sheen, which 40 C.F.R. § 110.1 defines as an “iridescent appearance on the surface of water.” The Oil Pollution Prevention regulations (discussed further below) also identify discharges from regulated facilities that require reporting, though there are exceptions—for example, when the discharge is in compliance with a permit under Section 402 of the CWA.

Under state and local laws, notification may be much more stringent. For example, California requires immediate reporting of “any significant release or threatened release” of a hazardous material, which includes oil. This can be subjective and requires a fact- and legal-specific evaluation of whether the release qualifies as “threatened” and/or “significant.” In Georgia, immediate notification is required either when the oil creates a “significant sheen on top of state waters” or when the amount discharged is unknown—further creating different criteria for when reporting is required. Regardless of what triggers notification, it is important that companies understand that different agencies—federal, state, and local—may each have different reporting requirements, and accurate and timely reporting is absolutely crucial. Often, failure to timely report is the first violation sought by agencies and can result in increased penalties and additional scrutiny.

What Authorities Are at Play?

At the federal level, two agencies primarily exercise authority over oil spills—the U.S. Environmental Protection Agency (EPA) and U.S. Coast Guard (CG). Depending on the location of the spill, the EPA or CG may lead federal oversight with the EPA overseeing inland spills and CG overseeing offshore spills. The Pipeline and Hazardous Materials Safety Administration and Federal Railroad Administration may also exercise authority for pipeline or railroad releases, respectively.

As mentioned above, Section 311 of the CWA and OPA—enacted in 1990 in response to the Exxon Valdez oil spill—make up the federal statutory framework for oil spills. In practice, these authorities are best categorized into two areas: (1) oil spill response; and (2) oil spill prevention and preparedness. It is important for companies to understand the expectations for both (discussed in more detail below), and the National Oil and Hazardous Substances Pollution Contingency Plan (often referred to as the National Contingency Plan or NCP), which outlines the federal government’s cleanup strategy for responding to oil spills, including other cleanups under CERCLA. The goal of the NCP is to ensure that resources are available and responses are consistent. Thus, when the federal government oversees a cleanup, the federal On-Scene Coordinator will expect that all response efforts, including those conducted by the responsible party, are consistent with the NCP.

At the state level, most utilize their respective water laws to address oil spills, though some states, like Louisiana, have laws comparable to OPA. At the local level, municipalities have notification and emergency response authorities that will be applicable. In the end, it’s very important that companies understand that several layers of government may have some form of oversight depending on the size, impact, and location of an oil spill.

OPA v. CWA

While the CWA and OPA are complimentary, including OPA amending the CWA, companies should understand the goals and implications of both. Generally, the CWA focuses on oil spill enforcement for cleanups and penalties, and the OPA broadens national and regional capability for preventing, responding to, and paying for oil spills.

For the CWA, Section 311(b)(3) expressly prohibits the discharge of oil (or hazardous substances) into or upon WOTUS and adjoining shorelines in quantities that may be harmful.1 For oil, this generally means discharges to WOTUS that cause sheening or violate applicable water quality standards. Sections 311(c) and (e) of the CWA provide extensive authority to the federal government to respond to these discharges, including threatened discharges, by issuing orders—either unilaterally or by consent—to owners, operators, or persons in charge of the facility from which the discharge occurs.

Sections 311(b)(6) and (7) of the CWA further empower the federal government to pursue significant penalties—both administrative and civil—for spills that reach WOTUS and/or when responsible parties fail to comply with an order. If gross negligence or willful misconduct is involved, you can expect even greater penalties—commonly more than three-fold—not to mention possible criminal liability. Internally, the EPA utilizes the Civil Penalty Policy for Sections 311(b)(3) and (j) of the CWA and factors outlined in Section 311(b)(8) of the CWA, including the seriousness of the violation, economic benefit to the responsible party, history of prior violations, and efforts to minimize or mitigate the discharge, to evaluate enforcement and penalty calculations.

Akin to the CWA, Section 2702(a) of OPA also makes responsible parties liable for removal costs and natural resource damages resulting from any discharge of oil, including a substantial threat of discharge, to WOTUS and adjoining shorelines. Notably, this includes not only costs incurred by the federal government, but also costs or damages to private parties, including damages for the loss of personal property, loss of revenues/profits due to injury, and cost of additional services during or after a spill. OPA further aims to strengthen national and regional response strategies, amend the National Oil and Hazardous Substances Pollution Contingency Plan, require facilities to develop prevention and response plans, and establish a fund for damages and cleanup costs—each discussed below.

While it is typically always the priority of the federal government to have responsible parties pay for and conduct their own spill cleanups, when a responsible party is unknown, unable, or refuses to pay, funds from the Oil Spill Liability Trust Fund (OSLTF) can be utilized to pay for the response. The OSLTF is managed by the CG’s National Pollution Funds Center (NPFC) and the NPFC thereby manages any oversight or cleanup costs incurred by the federal government. Thus, if an oil spill occurs at your facility and the federal government incurs costs responding or overseeing, the NPFC will be the entity that seeks recovery of those costs—even if the EPA later pursues penalties for the same discharge pursuant to Sections 311(b)(6) and (7) of the CWA. In addition, when a non-liable party performs a cleanup or incurs damages as a result of an oil spill, that party may file a claim for reimbursement directly against the responsible party and/or seek reimbursement from the NPFC.

Lastly, regarding liability, both the CWA and OPA are strict liability and provide limited liability defenses for acts of God, acts of war, or acts/omissions of third parties—comparable to CERCLA. Even so, it’s important to note that Section 309(g)(6) of the CWA states that the federal government may not seek enforcement, including penalties, if the state “has commenced and is diligently prosecuting an action” under a comparable state law. This includes issuing a final order or directing a responsible party to pay a penalty. As mentioned above, states typically pursue oil spill violations via their respective water laws, which may be considered comparable. State penalties may often be substantially less than those sought by the federal government—thus, early engagement with the state can be advantageous depending on the circumstances.

Oil Pollution Prevention Regulations

Section 311(j) of the CWA and OPA, as outlined in 40 C.F.R. Part 112, require facilities that store oil in significant quantities to prepare Spill Prevention, Control, and Countermeasure (SPCC) Plans to prevent accidental releases from reaching WOTUS or adjoining shorelines. Facilities with a greater risk of release and impact to WOTUS may also be required to develop a Facility Response Plan (FRP) to prepare for “worst-case spills.” At the outset, companies should confirm whether these regulations are applicable to their operations and facilities.

SPCC plans are required for facilities that are: (1) non-transportation-related (i.e., they store, process, or consume oil rather than simply move it from one facility to another); and (2) collectively store more than 1,320 gallons of oil above ground or 42,000 gallons below ground that could reasonably be expected to discharge oil to a WOTUS or adjoining shorelines. This can include oil drilling and production facilities, oil refineries, industrial, commercial, and agricultural facilities storing/using oil, facilities that transfer oil via pipelines or tank trucks (including airports), and facilities that sell or distribute oil, like marinas. Practically, these regulations require facilities to have a written plan certified by a professional engineer (apart from qualified facilities), maintain adequate secondary containment for oil storage, maintain updated lists of the federal, state, and local agencies that must be contacted in case of a spill, and follow regular inspection requirements, among other requirements.

In addition to SPCC, FRP plans are required for facilities that could reasonably expect to cause “substantial harm” to the environment by discharging oil into or upon WOTUS. They either have: (1) total oil storage capacity greater than or equal to 42,000 gallons and transfer oil over water to/from vessels; or (2) total oil storage capacity greater than or equal to 1 million gallons and either do not have sufficient secondary containment, are located at a distance such that a discharge could cause “injury” to habitat or shut down a drinking water intake, or within the past five years, have had a reportable discharge greater than or equal to 10,000 gallons. If so, given that FRP is self-identifiable, the facility must prepare and submit its FRP plan to its applicable EPA regional office. Among other things, these plans include evaluating , medium, and worst-case discharge scenarios, descriptions and records of self-inspections, drills, and response training, and diagrams of the facility site plan, drainage, and evacuation plan.

EPA commonly conducts inspections at subject facilities to ensure that SPCC and FRP plans are effectively implemented. Should your facility have an oil spill, plan on an inspection very soon to evaluate compliance and mitigation efforts with your respective requirements.

Suggested Actions

Beyond being aware of the above implications and requirements, below are several actions to consider to ensure compliance and minimize possible enforcement and/or litigation when the least expected occurs.

  • Act Fast: Should an oil spill occur, regardless of size, act fast to respond, mitigate, and determine if notification is required. This includes immediate internal coordination with those responsible for responding, as well as outreach to your environment counsel and/or consultant. If the determination for reporting is close, it is recommended that you report (with a qualified caveat) rather than withhold.
  • Education and Training: Ensure your staff is trained to effectively respond to, report, and prevent oil spills. Oil spills happen despite best attempts otherwise. When the inevitable happens, make sure facility staff are prepared to respond and mitigate the potential impacts of the spill, including having spill reporting hotlines and other contact numbers easily accessible and staff trained on where all information is located. Also, learn from past spills and/or near spills by conducting evaluations and identifying lessons learned to be utilized to prevent future spills.
  • Prepare for Outside Communication: If the spill is significant or causes public impacts, be prepared for outreach by the public, including local news and community groups. Notifications to the NRC are available online and impacts to public or private property often lead to alerts to local news and organizations. Ensure your public affairs contact(s) are aware and develop necessary communication, including desk statements, should the spill create public attention.
  • Review Compliance: Evaluate your current compliance with federal, state, or local requirements, including the development, assessment, and update (if needed) of SPCC and/or FRP response plans. This includes determining if either or both are required at your facility. Should a spill occur, it is important to make sure your response plans are up-to-date and ready for implementation.
  • Regular Audits and Updates: Periodically audit your spill response and prevention measures (SPCC and FRP plans), including any changes to facility operations, secondary containment features, or volumes of oil stored, to identify and correct inaccuracies and ensure that your plans are up-to-date. For FRP, this includes submitting updates to the appropriate EPA regional office within 60 days of each change that may materially affect the response to a worst-case discharge.
  • Insurance: Though not always necessary, consider appropriate insurance coverage to mitigate potential financial liabilities.
  • Consultation: If you have any doubts about your obligations during an oil spill or need assistance with compliance, please do not hesitate to contact your environment counsel or consultants for guidance and support.

1 While this discussion focuses on the impacts of oil spills, it’s important to remember that Section 311 of the CWA (though not OPA) also applies to hazardous substances—discharges to a WOTUS that exceed a reportable quantity pursuant to 40 C.F.R. § 117.3—though the federal government may typically utilize the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA or Superfund), or combination thereof, to pursue such releases.

© 2024 Beveridge & Diamond PC
For more news on Oil Spills, visit the NLR Environmental, Energy & Resources section.

Federal Court Directed to Rule on Challenge to WV Pooling Statute

A federal appeals court has instructed a lower court to resolve a pending suit challenging the constitutionality of West Virginia’s oil and gas pooling and unitization law. The federal district court previously declined to resolve certain constitutional issues presented in the suit on the grounds that those issues should be decided by a state court instead of a federal court.

In 2022, the West Virginia Legislature enacted Senate Bill 694 to revise West Virginia law governing the pooling and unitization of oil and gas formations associated with horizontal well development. Pooling and unitization essentially involves combining separately owned properties into a single “unit” through which one or more horizontal wells are drilled. The oil and gas produced from the horizontal well is then allocated among all the properties in the unit for purposes of calculating production royalties payable to the mineral owners.

Prior to Senate Bill 694 becoming effective on June 7, 2022, formation of a pooled unit for a horizontal well drilled through “shallow” oil and gas formations, which includes the Marcellus Shale, required consent of 100% of the mineral owners for all the properties to be included in the unit. This 100% consent requirement did not apply to horizontal wells drilled through “deep formations” such as the Utica Shale. One of the more significant changes made by SB 694 was to allow the West Virginia Oil and Gas Conservation Commission to approve units for shallow formations where at least 75% of the mineral owners consent, provided other requirements are also satisfied. This means that up to 25% of a unit could potentially include properties for which the mineral owner did not consent to being part of a unit.

Before Senate Bill 694 became effective, a pair of mineral owners (Scott Sonda and Brian Corwin) filed a lawsuit in the federal District Court for the Northern District of West Virginia seeking to preclude the law from taking effect. Governor Jim Justice was the only defendant named in the case. In their suit, Sonda and Corwin alleged that the law was illegal for several reasons, including the claim that the law authorizes the unconstitutional taking of private property without just compensation and deprives landowners of due process of law.

Federal Judge John Preston Bailey initially dismissed all of their claims for two reasons. First, Judge Bailey concluded that Sonda and Corwin lacked standing to bring the challenge because (a) their property had not been pooled into a unit without their consent and no operator had sought approval of a unit to include their property without their consent; and (b) the Commission, not the Governor, has the power to directly enforce Senate Bill 694.

Second, Judge Bailey ruled that, even if Sonda and Corwin established standing, Governor Justice had constitutional immunity from the suit because he had no direct authority to implement Senate Bill 694. Rather, the Commission has the authority to implement the law.

Instead of dismissing their suit entirely, Judge Bailey granted leave for Sonda and Corwin to amend their complaint to name the Commission as a defendant instead. Sonda and Corwin did so, and also named as defendants each person who serves on the Commission. The amended complaint still does not allege that mineral properties owned by Sonda or Corwin were pooled into a unit without their consent. Instead, the amended complaint attempts to address the standing issue by alleging that Senate Bill 694 effectively eliminates their ability to challenge whether they are being fairly compensated for oil and gas produced from their property that was pooled into a unit with their consent.

The Commission moved to dismiss the amended complaint for various reasons, including Sonda’s and Corwin’s lack of standing to bring the case. Judge Bailey did not address the standing issue, but agreed with the Commission with respect to three of the five claims asserted by Sonda and Corwin. Judge Bailey then abstained from addressing the Commission’s arguments for dismissal of the other two claims, which asserted constitutional violations, because he believed that those issues were more appropriate for resolution by a state court instead of a federal court.

The Commission appealed Judge Bailey’s decision to abstain from addressing the arguments for dismissal of the constitutional claims. By opinion issued on January 31, 2024, the Fourth Circuit Court of Appeals ruled that Judge Bailey should not have abstained. The appellate court also directed Judge Bailey to first address the standing issue before addressing any other pending issue. The opinion does not specify a deadline for Judge Bailey to rule on those issues. If Judge Bailey finds that Sonda and Corwin continue to lack standing to assert their claims, the case will presumably be dismissed on that ground alone. If Judge Bailey concludes that Sonda and Corwin have established standing, Judge Bailey will likely address the merits of the Commission’s other arguments for dismissal.

© Copyright Babst, Calland, Clements and Zomnir, P.C.
For more news on the Constitutionality of West Virginia’s Oil and Gas Laws, visit the NLR Election Law / Legislative News section.

USDA Requesting Comments on New AFIDA Regulations that Could Impact Renewable Energy Developers

On December 18, 2023, the Farm Service Agency of the United States Department of Agriculture published Notice in the Federal Register that it is considering changes to its FSA-153 Form required to report foreign interests in agricultural land pursuant to the Agricultural Foreign Investment Disclosure Act (“AFIDA”), 7 U.S.C.A.§ 3501 et seq.

Interested stakeholders are invited to provide comments regarding the proposed changes no later than February 16, 2024. The Federal Register Notice is available in its entirety via the following link: https://www.federalregister.gov/documents/2023/12/18/2023-27683/request-for-information-on-agricultural-foreign-investment-disclosure-act-afida-fsa-153-form.

Many renewable developers are subject to AFIDA and regularly report long-term wind and solar leasehold interests to the USDA. The changes proposed by the USDA may directly impact the data required to be reported by renewable developers. In additional to comments requested on other AFIDA reporting matters, the USDA requests public input on the following:

(1) Are long-term leasehold filings—particularly those in the wind turbine and solar panel industries—“different enough” from land ownership purchase or sale filings that a separate version of the FSA–153 form should be created? Should a different “logic path” of questions be developed for long-term leasehold filings?

(2) Many foreign wind energy companies have long-term leaseholds on U.S. agricultural land farmed by U.S. producers that trigger the AFIDA reporting requirement. Currently, the entire acreage of the parcel is captured; this is because the number of wind turbines that will be established on the land (if any) is often an unknown at the time of AFIDA reporting. In addition, the existence of the leasehold generally precludes other energy company involvement on the acreage. Does this approach overstate foreign energy company activity on U.S. agricultural land? If so, how should the acreage associated with these leaseholds be captured?

(3) How should solar panels or photovoltaics—which are situated above the agricultural land—be treated for AFIDA reporting given that AFIDA uses an acreage basis for reporting?

(4) Some foreign owners are providing a very low estimate of the value of the lease (as the flat payment is low) on the FSA–153 form while others are providing the estimated value of the entire parcel. How should “interest in the value of the agricultural land” be defined for leases?

(5) In addition to the legal description of each leasehold parcel already required to be reported on Form FSA-153, is it an undue burden on foreign owners or their representatives to require one or more of the following: (a) the longitude and latitude for each parcel; (b) the property tax ID number assigned by the county; and (c) the FSA tract number and the FSA farm number?

As many renewable developers are aware, AFIDA imposes reporting requirements with respect to the acquisition or disposition of interests in agricultural property by a foreign-owned entity or an entity in which a “significant interest or substantial control” is held by a non-U.S. parent.

Sales and acquisitions in particular may be highly scrutinized by the USDA to ensure that a disposition is filed by the selling entity and an acquisition form is filed by the acquiring entity. If, for example, an entity sells a portfolio of wind or solar leases, that entity should file FSA-153 dispositions, and the purchaser should file FSA-153 acquisitions for the same property. In addition to acquisitions and dispositions, reporting of an amended FSA–153 is triggered when the land use changes, the tiers of ownership change, or the name of the foreign person changes.

Although AFIDA’s requirements have been in existence for many years, the USDA’s recent imposition of significant fines and penalties (up to 25% of the FMV of the property) to developers who fail to file (or are late to file) FSA-153 reports has engendered a new interest in AFIDA and made it more crucial to consider these reporting requirements in any diligence analysis.

Significant interest or substantial control is defined by Federal regulations as an ownership interest of ten percent or more. “Foreign owners” also includes long-term leaseholders in the wind and solar industries.

AFIDA generally defines “agricultural land” as ten acres or more of land that has been used for agricultural purposes (e.g. farming, cropland, ranching, grazing, timber production) within the last five years. These definitions apply even if the land has been planned and plotted or re-zoned for nonagricultural purposes.

Agricultural land is categorized as cropland, forestland, pastureland, other agriculture, and non-agricultural land (homesteads, farm roads).

7 C.F.R. §781.2(c) defines “any interest in real property” as all interest acquired, transferred or held in agricultural lands, except:
(1) Security interests;
(2) Leasehold interests of less than ten (10) years;
(3) Contingent future interests;
(4) Noncontingent future interests which do not become possessory upon the termination of the present possessory estate;
(5) Surface or subsurface easements and rights of way used for a purpose unrelated to agricultural production, and;
(6) An interest solely in mineral rights.

© Polsinelli PC, Polsinelli LLP in California
For more news on Agricultural Land and Renewable Energy Developers, visit the NLR Environmental, Energy & Resources section.

U.S. EV Sales Are Slowing: Implications for the Auto Industry

Throughout the past decade, analysts and policymakers have promoted electric vehicles (EVs) as the cars of the future, highlighting their potential to provide effective, environmentally friendly transportation for individual and business purposes alike. Pure EV sales in the United States rose from just over 10,000 in 2011 to nearly 500,000 in 2021, and the country is expected to add 1 million new EVs to its roads in 2023, aided by government subsidies. However, over the past year, the EV market has been struggling with price cuts and rising inventories; in August 2023, it took about twice as long to sell an EV in the U.S. as it did the previous January. Given the expectations for an EV takeover of the automotive industry, it is important to understand what is driving this slowdown, and how it may affect individuals and businesses in the years to come.

The Transportation of Tomorrow

Though fuel-powered motors were traditionally preferable due to their superior energy storage and range, concerns over their environmental impact in the late 20th century propelled people to consider electricity-powered substitutes. Hybrid EVs, which use electric motors alongside internal combustion engines, became more widespread starting in the 1990s, while fully battery-powered electric cars, which only use energy stored in on-board batteries, have increasingly become practical options in the consumer market starting in the 2010s, though their recharging requirement remains a sore spot. Given the efficiency gap between fuel-powered motors and contemporary battery technologies, as well as typically higher costs for EV production, governments have often stepped in to offer economic incentives for EV purchasing and manufacturing, attempting to guide long-term automotive supply and demand toward sustainable transport options.

Government incentives for EV adoption have grown steadily over the past three decades, with large markets like the U.S. and EU commencing efforts in the 2000s, later followed by developing economies such as China and India. For years, the U.S. federal government and state governments have offered tax credits for producers and consumers adopting qualified electric drive motor vehicles, with states like California going even further by offering HOV lane access for EVs operated by a single occupant. President Biden designated increased EV adoption as a substantial element of his Investing in America agenda, setting a goal for 50% of all new vehicle sales in the U.S. to be electric by 2030. However, despite increasing environmental awareness and policy pressures, consumer demand has not always followed suit.

Wavering Consumer Demand

Currently, there is an oversupply of electric vehicles in the industry, reflecting continued automaker and government investment against slowing consumer demand. While most American consumers view adopting EVs as an inevitability, their anxieties relating to the range that the battery can produce and a lack of public charging infrastructure still induce uncertainties over dependability. During the COVID-19 pandemic, shelter-in-place orders reduced the need for frequent personal transportation, allowing consumers greater flexibility to adopt EVs. However, now that pandemic restrictions no longer present a substantial external variable and more workers are required to return to the office, vehicles powered by internal combustion engines remain preferable as the most reliable transport option. This is supported by the changing profile of the EV consumer – the percentage of EV shoppers trading in a vehicle they already own has doubled over the past decade, indicating that many EV consumers do not rely on them as their primary mode of transport. Amplifying the charging concern, a Pew Research Center survey from July found that Americans have low levels of confidence that the U.S. will build necessary EV infrastructure, including critical charging ports, dampening enthusiasm that the Biden administration’s EV goals will be met on time.

On the other hand, pricing continues to be another hurdle for greater EV adoption. According to Cox Automotive, the average transaction price for a vehicle in the U.S. was around $48,000 in September 2023; for EVs, the number was between $53,000 and $60,000. The higher price tag for EVs tends to be a result of manufacturing costs remaining more expensive than they would be for producing gasoline-powered vehicles, given the auto industry’s substantially longer experience making internal combustion engines compared to EV technologies and the still-inflexible EV supply chain. High interest rates render borrowing money for car payments more expensive, along with inflation reducing consumer purchasing power and global supply chain disruptions contributing to the issue as well. According to S&P Global Mobility, while 86% of U.S. car buyers were considering an EV in 2021, the number fell to 67% in 2023. Despite government tax credits, investing in a relatively more expensive EV purchase is a hefty request for many American consumers concerned about short-term costs in today’s economy.

Effects on the Auto Industry

The auto sector is facing the classic problem for a sector in transition, i.e., growing supply to pace with developing demand. The current market condition is not a problem of declining demand but supply outpacing demand and the auto industry is already making corrections. Ford, having opened reservations for its fully electric F-150 Lightning model in May 2021, closed them by the end of the year due to excess supply, and by September 2023, announced it was ramping up production of its hybrid F-150s in response to lowered than anticipated sales of the Lightning. Lucid, a high-profile luxury EV brand, has seen two consecutive quarters of weaker than expected demand, most recently delivering 600 fewer of its Air luxury sedans than Wall Street had expected in the second quarter of 2023. Tesla’s aggressive price cuts have hindered the growth of competition in the EV industry, with two-thirds of all EVs sold by the Elon Musk-owned automotive giant, as consumers find it difficult to afford suitable alternatives. At the end of the second quarter of 2023, several automakers announced their decision to move to the Tesla charging standard, stranding many vehicles on factory floors with an obsolete charging outlet, thus further exacerbating the dilemma.

Pushback against public sector efforts to mandate EV adoption may also reshape expectations for how the auto industry will move forward in the coming decade. On November 8, the U.S. Senate voted 50-48 to overturn Biden’s decision to waive some “Buy America” requirements for government-funded electric vehicle charging stations. Western lithium and graphite miners have started charging the EV supply chain higher prices to reduce dependence on Chinese supply of these materials. Owing to anxieties over cheap Chinese-manufactured EVs flooding the American market as has happened in Europe and a potential Chinese monopoly of rare earth minerals critical in EV production, these protectionist moves on an already inflexible EV supply chain are likely to further delay progress toward the administration’s vehicle electrification aims. EV adoption also remains inconsistent across U.S. regions, being significantly lesser in states like Texas where gas prices and home energy rates are lower, compared to others like California where the opposite is true. Nonetheless, there are reasons to remain optimistic about the long-term growth of EV sales in the auto industry – an S&P study in 2023 showed that people were willing to accept charging times of less than an hour and less range on an EV compared to a gasoline equivalent, and while the number of EV buyers fell from 2021 to 2023, it was still higher than in 2019. Understanding that a gradual shift towards electricity-powered vehicles is still probable, individuals and businesses alike should note that it will likely occur over a longer period than analysts and policymakers predict. Meanwhile, greater hybrid vehicle production and purchasing could generate a slew of new opportunities in the short to medium term.

 

This article was authored by William Samir Simpson.

© 2023 Bradley Arant Boult Cummings LLP
For more news on Electric Vehicle Sales, visit the NLR Utilities & Transport section.

Taking Stock of a Big Month for Methane Policy

November has been a big month for methane policy, featuring announcements of new international, domestic, and private sector initiatives.  A common thread across all of the new initiatives is the aim of achieving more ambitious, credible, and internationally consistent standards for measurement, monitoring, reporting, and verification (MMRV) of methane emissions from the oil and gas sector.  Below is a review.

China’s Methane Pledge.  China is the world’s largest emitter of methane, accounting for 14% of the global total, and, for the first time, the government made an international announcement about methane policy.  At a November summit held in Sunnylands, California, President Joe Biden and Chinese President Xi Jinping announced a new agreement to address climate change. Previous Chinese pledges had only targeted carbon dioxide, but the new agreement includes a first-ever commitment by the country to tackle non-CO2 emissions, including methane.  Just prior to the Sunnylands summit, the Chinese government issued an action plan outlining goals to curb flaring and to develop a methane MMRV program.

EU Methane Regulation.  The European Union (EU) also broke new ground on methane policy this month.  After all-night talks, the EU’s governing entities finalized a new Methane Regulation, which targets not only domestic sources of methane but also emissions attributable to imports of natural gas into the Continent—including from the United States. For imports, the Regulation establishes phased requirements.  The first phase focuses on data collection coupled with a mechanism for detecting and rapidly addressing large leaks.  The second phase will condition imports on application of prescribed, uniform MMRV measures.  Starting in 2030, importers will be subject to a limit on their methane “intensity”—a metric that measures methane emissions per unit of gas throughput.  The methane intensity limit will apply across the entire value chain, from pre-production through final delivery.  The Regulation requires the EU Commission to promulgate the intensity standard by 2027.

International Working Group on MMRV for Natural Gas Markets.  To support not only these emerging governmental policies but also expanding private sector efforts to create a market for “Differentiated Gas,” a multilateral initiative was announced in November—the International Working Group to Establish a Greenhouse Gas Supply Chain Emissions Measurement, Monitoring, Reporting, and Verification (MMRV) Framework for Providing Comparable and Reliable Information to Natural Gas Market Participants (the Working Group). The Working Group’s members consist of the U.S. government, eleven other governments, the European Commission, and the Mediterranean Gas Forum.  The Working Group’s objective is to develop a consensus-based, consistent international framework for supply chain MMRV.  A consistent framework will make it easier for buyers to demand and suppliers to provide natural gas with a lower greenhouse gas profile.  The Working Group will not prescribe emission targets, but it acknowledges that governments may use its work products to inform regulatory processes.

The Working Group has stated that it will draw on input from expert stakeholders.  To that end, a consortium of three universities participating in the Energy Emissions Modeling and Data Lab (EEMDL) has convened a group of academic, think tanks, ENGO, and market experts to develop recommendations for MMRV standards for the Differentiated Gas market. (I am a participating expert in the EEMDL initiative.)  This month, a subset of the experts group published a paper in Nature Energy outlining the issues.

Financial Institutions Call for Industry Action.  Underscoring the increasing private sector demand for Differentiated Gas, two major financial institutions released reports in November calling for industry action.  JP Morgan, one of the world’s largest financiers of fossil fuel projects, issued a report underscoring its commitment to achieve a net zero-aligned emission intensity reduction target for its oil and gas sector portfolio. Methane reductions are a key element of its net-zero strategy.  To that end, the report identifies and exhorts the industry to adopt best-in-class practices for methane MMRV and mitigation.

In the same week, one of the world’s largest insurance underwriters for the oil and gas sector, Chubb, rolled out a Methane Resource Hub, a digital resource center for its clients. The site provides information on MMRV and mitigation techniques, technologies, studies, and policies.

Waiting for EPA.  Also expected in November is EPA’s proposed implementation rules for the “Methane Fee” that was enacted as part of the Inflation Reduction Act (IRA).  The IRA provisions apply a per-ton fee to facilities in the oil and gas sector that exceed specified methane intensity limits.  To implement the fee, EPA will need to promulgate methods for facility-level methane intensity measurements.  A significant issue in the rulemaking is the extent to which EPA will allow affected facilities to use advanced methane measurement technologies to calculate their annual emissions.

© 2023 Van Ness Feldman LLP
For more news on methane policy, visit the NLR Environmental, Energy & Resources section.

EPA Ramps Up Climate Enforcement

Facilities operating across the country need to be prepared for increased climate-driven enforcement at all levels of federal government—especially at the U.S. Environmental Protection Agency (EPA). With EPA’s Climate Enforcement and Compliance Strategy announcement last week, the Agency has gone all-in on enforcement and compliance programs “to address climate change, wherever appropriate, in every matter within their jurisdiction.” This initiative is consistent with President Biden’s Executive Order 14008, which calls for a government-wide approach to tackling the climate crisis. The strategy also underscores the Agency’s announcement of its first-ever National Enforcement and Compliance Initiative (NECI) on climate change, which targets, among others, methane emissions at oil and gas facilities and landfills, as well as illegal importation of hydrofluorocarbons (HFCs). Companies with exposure to high-Greenhouse Gas (GHG) emissions and related climate risks, both in the Clean Air Act (CAA) and non-CAA context, should be on notice of increased scrutiny moving forward, including climate-focused auditing and inspections by the Agency and GHG-driven injunctive relief.

In the wake of EPA’s announcement of this new enforcement and compliance strategy, watch for the following developments:

  • EPA will increasingly prioritize enforcement and compliance actions to mitigate climate change, including further scrutiny of high-GHG emitters through information requests, inspections, and formal enforcement. Oil and gas facilities and landfills have been specifically targeted, but any facility with high GHG emissions should expect greater enforcement scrutiny.
  • Enforcement demands will likely include higher penalties, compared to other non-GHG-driven cases, more GHG-related injunctive relief, as well as more climate adaptation and resilience requirements. This relief could include more fence-line monitoring or flare gas reductions or recovery, among other priorities.
  • Climate-focused injunctive relief measures will not be limited to CAA. Expect a renewed emphasis on green remediation technologies at Superfund and Resource Conservation and Recovery Act corrective action sites, as well as a push for green infrastructure, resiliency planning, and stormwater management enhancements in Clean Water Act settlements.
  • Plan for EPA to scrutinize GHG emissions reports more closely. Carefully evaluate these submissions to ensure consistency with reporting regulations.
  • EPA will be interested in Supplemental Environmental Projects that reduce GHGs.  Consider clean and renewable energy projects or other GHG mitigation projects as part of any strategy to resolve an enforcement case, particularly if the penalty demand is large.

Facilities located in Environmental Justice (EJ) communities should particularly expect additional climate-related scrutiny, as EPA has indicated that “[t]hese efforts are particularly necessary in overburdened and marginalized communities that are on the frontlines of the climate crisis.” Facilities will need to engage in more extensive consultation with local communities to evaluate remedy selection, including any climate adaptation efforts, as well as more protracted enforcement negotiations to evaluate community-focused injunctive relief (i.e., climate risk reporting, additional community engagement, etc.).

Finally, be prepared to respond to these issues quickly, including the Biden Administration’s broader EPA enforcement agenda, which is expected to increase enforcement dramatically over the coming months and years. Apart from EPA, broader scrutiny of corporate climate reporting will become more common as the Securities and Exchange Commission looks to finalize its proposed Climate Risk Disclosure Rule, requiring public companies to disclose climate-related risks and emissions data, among other requirements. Facilities should review publicly available information and emissions reporting for consistency and accuracy.

© 2023 Beveridge & Diamond PC
Article by: Andrew C. Silton , Allyn L. Stern , Barbara M.R. Marvin of Beveridge & Diamond PC 
For more articles on the EPA, visit the NLR Environmental, Energy and Resources section.

Renewable Energy Tax Credit Transfer Guidance Provides Both Clarity And Pitfalls

Highlights

The renewable tax credit transfer market will accelerate with new government guidance; public hearing and comments deadlines are scheduled for August

Risk allocation puts the usual premium on sponsors with a balance sheet and/or recapture insurance coverage

While the guidelines provide clear rules and examples, many foot faults are present

On June 14, 2023, the Treasury Department and Internal Revenue Service issued long-awaited guidance on the transferability of certain renewable energy-related federal tax credits. The guidance takes the form of a notice of proposed rulemaking, proposed regulations, and an online Q&A, with a public hearing to follow in August.

Under new Code Section 6418, eligible taxpayers can elect to transfer all or any specified portion of eligible tax credits to one or more unrelated buyers for cash consideration. While the tax credits can be sold to more than one buyer, subsequent transfers by the buyer are prohibited.

This alert highlights several practical issues raised by the guidance, which should allow participants waiting for more clarity to proceed.

Individual Buyers Left Out

  • The guidance applies the Code Section 49 at risk rules and Section 50(b) tax-exempt use rules, generally restricting sellers in calculating the amount of tax credits for sale, and Code Section 469 passive activity rules, generally restricting buyer’s use of such tax credits, in various contexts. On the buyer side, these rules appear to be more restrictive than the limitations that would apply to identical tax credits in an allocation, rather than sale, context. Suffice to say, this will prohibit individuals from taking part in the transfer market for practical purposes outside of fact patterns of very limited application.
  • While this result may not be surprising since such rules currently severely restrict individuals from participating in traditional federal tax credit equity structures, there was some hope for a different outcome due to the stated policy goal of increasing renewable energy investment (not to mention the Inflation Reduction Act’s general departure from decades of case law precedent and IRS enforcement action prohibiting sales of federal tax credits with the enactment of Section 6418).

Lessees Cannot Sell the Tax Credits

  • A lessee cannot transfer the credit. With the prevalence of the master lease (inverted lease) structure in tax equity transactions, this prohibition created an unexpected roadblock for deal participants who have been structuring tax equity transactions with backstop type sale provisions for almost a year now. This presents developers, at least in the inverted lease context, with a choice of utilizing a traditional tax equity structure for the purpose of obtaining a tax-free step up in basis to fair market value, or forgoing the step up for less financing but also less structure complexity. The standard partnership flip project sale into a tax equity type of holding company structure could still remain a viable alternative.
  • As the transfer is generally made on a property-by-property basis by election, creative structuring, in theory, could allow for a lessor to retain certain property and sell the related tax credits (e.g., on portfolios with more than one solar installation/project, or even with large projects that go online on a block-by-block basis assuming the “energy project” election is not made – a term that future guidance will need to provide more clarity on).
  • However, this seems to be an ivory tower conclusion currently, and the practical reality is that too many unknown issues could be raised by such out of the box structuring, including the fact that conservative institutional investors may refuse to participate in such a structure until clear objective guidance is published addressing the same.

Bonus Credits Cannot Be Sold Separately

  • Bonus credits cannot be sold separately from the underlying base credit. This is more problematic for certain adders – for example, the energy community adder rules are now out and amount to simply checking a location on a website. Others (e.g., the low-income community or domestic content adder) require more extensive and subjective application and qualification procedures which makes when and how such adders can be transferred difficult to ascertain. Projects hoping to transfer such credits may need to be creative in compensating buyers for such uncertainty and qualification risk. Tax equity transactions that closed prior to the guidance’s issuance may also need to be revisited, as provisions in such transaction documents commonly attempted to bifurcate the bonus credit away from the base credit in order to allow the sponsor to separately sell such adders.

Buyers Bear Recapture Risk and Due Diligence Emphasis

  • While the Joint Committee on Taxation Bluebook indicated the buyer is responsible for recapture, industry participants were still hoping such risk would remain with the seller. Outside of the limited situation of indirect partnership dispositions (which still results in a recapture event to the transferring partner if triggered), the recapture risk is borne by the buyer, using the rationale that the buyer is the “taxpayer” for purposes of the transferred tax credits. While this is familiar territory for tax equity investors, whose allocated tax credits would be reduced in a recapture scenario, tax credit purchase transactions are now burdened with what amounts to the standard tax equity type of due diligence, including negotiation of transaction documents outside of a basic purchase agreement.
  • The guidance provides that indemnity protections between the seller and buyer are permitted. Tax equity transactions historically have had robust indemnification provisions, which should remain the case even more so in purchase/sale transactions. Tax equity investors traditionally bear “structure risk” dealing with whether the investor is a partner for tax purposes – such risk is eliminated in the purchase scenario as the purchasing investor no longer needs to be a partner (subject to the caveat of a buyer partnership discussed below).
  • If the buyer claims a larger credit amount than the seller could have, such “excessive credit transfer” will subject the buyer to a 20 percent penalty on the excess amount (in addition to the regular tax owed). All buyers are aggregated and treated as one for this purpose – if the seller retains any tax credits, the disallowance is first applied to the seller’s retained tax credits. A facts and circumstances reasonable cause exception to avoid this penalty is provided, further emphasizing the need for robust due diligence.
  • Specific non-exclusive examples that may demonstrate reasonable cause include reviewing the seller’s records with respect to determining the tax credit amount, and reasonable reliance on third-party expert reports and representations from the seller. While not unique to this new tax credit transfer regime, the subjective and circular nature of such a standard is complex – for example, when is it not “reasonable” for buyers or other professionals to rely on other board certified and licensed professionals, such as an appraiser or independent engineer with specialized knowledge?
  • Buyers thus need to remain vigilant about potential recapture causing events. For example, tax equity investors will not generally allow project level debt on investment tax credit transactions without some sort of lender forbearance agreement that provides that the lender will not cause a tax credit recapture event (such as foreclosing and taking direct ownership of the project). Buyers remain responsible for such a direct project level recapture event, which again aligns the tax credit transfer regime with tax equity due diligence and third-party negotiation requirements. The guidance is more lenient for the common back-leverage debt scenario.
  • While similar interparty agreements between back leverage lenders and the tax equity investor are required for non-project level debt facilities to address tax credit recapture among other issues, the guidance provides that a partner disposing of its indirect interest in the project (e.g., the lender foreclosing and taking ownership of a partner’s partnership interest) will remain subject to the recapture liability rather than the buyer provided that other tax-exempt use rules are not otherwise implicated. However, the need to negotiate such lender related agreements is still implicated as not all recapture risk in even this scenario was eliminated to the buyer.
  • While the recapture risk could place a premium on production tax credit deals (that are technically not subject to recapture or subjective basis risk), the burdensome process of needing to buy such tax credits on a yearly basis in line with sales of output may make such transactions more tedious.
  • The insurance industry already has products in place to alleviate buyer concerns, but this is just another transaction cost in what may be a tight pricing market. Not unlike tax equity transactions, sponsor sellers with a balance sheet to backstop indemnities may be able to demand a pricing premium; other sponsors may need to compensate buyers with lower credit pricing to reward such risk and or/to allow the purchase of recapture insurance. While this seems logical, the guidance also includes anti-abuse type rules whereby low credit pricing could be questioned in terms of whether some sort of impermissible transfer by way of other than cash occurred (e.g., a barter for some sort of other service). What the IRS subjectively views as “below market” pricing could trigger some sort of audit review based on this factor alone which further stresses the importance of appropriate due diligence.

Partnerships and Syndications

  • The guidance provides very clear rules with helpful examples, which should allow partnership sellers and buyers to proceed with very objective parameters. For example, the rules allow a partnership seller to specify which partner’s otherwise allocable share of tax credits is being sold and how to then allocate the tax-exempt income generated. The cash generated from sales can be used or distributed however the partnership chooses.
  • Similar objective rules and examples are provided for a buyer partnership. Subsequent direct and indirect allocations of a purchased tax credit do not violate the one-time transfer prohibition. Purchased tax credits are treated as “extraordinary items” that must be allocated among the partners of the buyer partnership as of the time of the transfer, which is generally deemed to occur on the first date a cash payment is made. Thus, all partners need to be in the partnership on such date to avoid an issue. Purchased tax credits are then allocated to the partners in accordance with their share of the nondeductible expenditures used to fund the purchase price.
  • What level of end-user comfort is needed in such a syndicated buyer partnership is an open question. While the rules provide objective guidelines in terms of when and how such purchased credits are allocated, subjective questions that are present in (and focused on) traditional tax equity partnerships are implicated. For example, could a syndication partnership set up for the business purpose of what amounts to selling the tax credits somehow run afoul of the subjective business purpose and disguised sale rules in tax credit case precedent, such as the Virginia Historic Tax Credit Fund state tax credit line of precedent? Will the market require a robust tax opinion in such scenario, thereby driving up transaction costs?
  • An example in the proposed regulations speaks to this sort of partnership formed for the specific purpose of buying tax credits, but leaves out of the fact pattern a syndicator partner. The example itself should go a long way towards blessing such arrangements, but the IRS taking a contrary position when dealing with such issues would not be a new situation. For example, the IRS challenged allocations of federal historic tax credits as prohibited sales of federal tax credits to the point of freezing the entire tax equity market with its positions in Historic Boardwalk Hall, which was only rectified with the release of a subsequent safe harbor revenue procedure.
  • Moreover, the guidance provides that tax credit brokers are allowed to participate in the market so long as the tax credits are not transferred to such brokers as an initial first step in the transfer process (as the subsequent transfer to an end user would violate the one-time transfer rule). Specifically, at no point can the federal “income tax ownership” be transferred to a broker. It is an open question if further distinction will be made at where this ownership line should be drawn. For example, can a third party enter into a purchase agreement with a seller and then transfer such rights prior to the transfer election being made? Does it matter under such analysis if 1) purchase price installments have been paid (which implicates rules in the buyer partnership context as noted above) and/or 2) the tax credit generating eligible property has been placed in service (which is when the investment tax credit vests for an allocated tax credit analysis; a production tax credit generally arises as electricity or the applicable source is sold)?
  • Indirectly implicated is what effect the new transfer rules will have on established case law precedent and IRS enforcement action in traditional tax equity structures. The Inflation Reduction Act and guidance dances around certain of these issues by creating a fiction where the buyer is treated as the “taxpayer” – this avoids the issue of turning a federal tax credit into “property” that can be sold similar to a certificated state tax credit. This also provides a more logical explanation as to why the buyer of these federal tax credits does not need to report any price discount as income when utilized, unlike the well-established federal tax treatment of certificated state tax credits that provides the exact opposite (e.g., a buyer of a certificated state tax credit at $0.90 has to report $0.10 of income on use of such tax credit).

Other Administrative and Foot-Fault Issues

  • The purchase price can only be paid in cash during the period commencing with the beginning of the seller’s tax year during which the applicable tax credit is generated and ending on the due date for filing the seller’s tax return with extensions. Thus, such period could be as long as 21.5 months or more (e.g., a calendar year partnership seller extending its return to Sept. 15). Tax equity transactions generally have pricing timing adjusters for failure to meet placement in service deadlines. Such mechanism will not work if advanced payments were made and then the project’s projected placement in service year changes. Tax credit purchase agreements executed prior to the June 14 guidance may require amendments or complete unwinds to line up with the rules to avoid foot faults (e.g., purchase agreements executed in 2022 where a portion of the purchase price was paid in 2022 for anticipated 2023 tax credits would not fall within the “paid in cash” safe harbor period). Advanced commitments, so long as cash is not transferred outside of the period outlined above, are permitted.
  • The typical solar equity contribution schedule of 20 percent at a project’s mechanical completion makes purchase price schedules approximating the same a reasonable adjustment for most investment tax credit energy deals in terms of the timing of financing. In addition, the advance commitment blessing of the guidance will give lender parties the comfort necessary similar to having executed tax equity documents in place. Thus, typical project construction financing mechanisms should be similar in the tax equity versus purchase agreement scenario, with projects that allow for a more delayed funding mechanism possibly obtaining a tax credit pricing premium. Production tax credit deals, for which tax credits can only be paid for on a yearly basis within the cash paid safe harbor timing window, may have more significant project financing hurdles without further tax credit transfer rule modifications.
  • Sellers can only make the transfer election on an original return, which includes extensions. Buyers, by contrast, may claim the purchased tax credit on an amended return.
  • Buyers need to be aware that usage of the purchased tax credits is tied to the tax year of the seller. For example, a fiscal year seller could cause the tax credits to be available a year later than an uninformed buyer anticipated, regardless of when the tax credit was generated using a traditional placement in service analysis. For example, a solar project placed in service during November 2023 by an August fiscal year seller would generate credits first able to be used in a calendar year buyer’s 2024, instead of 2023, tax year. A buyer can use the tax credits it intends to purchase against its estimated tax liability.
  • The pre-registration requirements, which are expansive and open-ended, are also tied to the taxable year the tax credits are generated and generally must be made on a property-by-property basis. For example, 50 rooftop installations could require 50 separate registration numbers outside of the “energy project” election. When such registration information needs updated is also not entirely clear – for example, a project is often sold into a tax equity partnership syndication structure on or before mechanical completion. Needing to update registration information could delay transactions and implicates unknown audit risk.

While these rules provide much-needed clarity, failure to adhere may be catastrophic and will require sellers and buyers to put proper administrative procedures in place to avoid foot faults. The new transfer regime will expand the market to new buyers who may have viewed tax equity as either too complex or had other reasons to avoid these transactions, such as the accounting treatment of energy tax credit structures. However, it would be prudent for such buyers to approach such transactions with eyes wide open.

© 2023 BARNES & THORNBURG LLP

For more Tax Legal News, click here to visit the National Law Review.