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    Environmental Law Fall 2024 Report

    Eric Benjamin Gallon, Zac Lackey, Kyle Chandler Gilliam, Kristy A Bulleit, Conrad Bolston, Kerry L McGrath, and Brian Levey

    Nov 15, 2024

    41 min read

    Electric Grid Electricity Energy Environment Federal Agencies Oil and Gas Regulation State Regulatory Water

    Summary

    • The U.S. Environmental Protection Agency (EPA) released its National Enforcement and Compliance Initiatives for Fiscal Years 2024-2027.
    • In 2020, the EPA released a final rule revising the effluent limitations guidelines for bottom ash transport water and flue gas desulfurization water, two waste streams commonly produced by coal-fired steam electric plants.
    • President Biden signed the Fiscal Responsibility Act of 2023, Public Law 118-5, which includes several amendments to streamline National Environmental Policy Act reviews.
    Environmental Law Fall 2024 Report
    grandriver via Getty Images

    The Committee on Environmental Law’s report for Fall 2024 summarizes key environmental law developments at the United States Environmental Protection Agency (EPA) and in the federal courts between April and October 2024, with a particular focus on developments of interest to the aviation, electric, and locomotive industries and to infrastructure projects more generally. You’ll find hyperlinks to relevant articles, rulemakings, statutes, regulations, and other documents throughout the report. Quotes are taken from the nearest hyperlinked source unless otherwise stated or indicated. Dates are from this year unless otherwise stated.

    Electricity

    Coal Combustion Residuals Rule

    In 2015, EPA promulgated its Coal Combustion Residuals rule under Subtitle D of the Resource Conservation and Recovery Act (RCRA). The rule established numerous requirements for the disposal of coal combustion residuals (CCR) in landfills and surface impoundments, including structural integrity design criteria and safety assessment requirements; liner requirements for new and expanded impoundments and landfills; site restrictions for new landfills and surface impoundments; groundwater monitoring requirements; requirements for closing CCR units; and more.

    In 2018, EPA finalized amendments to the 2015 CCR Rule. The amendments permitted EPA (or states with approved programs) to “[s]uspend groundwater monitoring requirements if there is evidence that there is no potential for migration of hazardous constituents to the uppermost aquifer during the active life of the unit and post-closure care … .” They allowed permitting authorities (and not just professional engineers) to certify that facilities comply with the CCR Rule’s requirements. They established risk-based groundwater protection standards (GWPS) for the four constituents in 40 CFR Part 257, Appendix IV, without maximum contaminant levels (MCLs) under the Safe Drinking Water Act. And they extended the deadline by which surface impoundments were required to stop accepting CCR and close if they could not comply with the requirement in 40 C.F.R. § 257.60 to place facilities at least five feet above the upper limit of the uppermost aquifer, or if they are unlined and leaking, causing a statistically significant increase over the GWPS. The 2018 rule was challenged in the United States Court of Appeals for the D.C. Circuit, and ultimately remanded without vacatur for reconsideration.

    In August 2018, the D.C. Circuit issued Utility Solid Waste Activities Group v. EPA, 901 F.3d 414 (D.C. Cir. 2018), which granted in part certain environmental organizations’ challenges to the 2015 CCR Rule and remanded certain provisions of the rule at EPA’s request. The court found that the rule’s provisions allowing “existing, unlined surface impoundments to continue operating until they cause groundwater contamination” were “arbitrary and contrary to RCRA” because groundwater contamination would not be “promptly detected,” “promptly stopped,” or remedied “once it occurs.” The court struck down provisions treating clay-lined impoundments as if they were lined with geomembranes, finding those provisions “failed to ensure ‘no reasonable probability’ of adverse effects to the environment, as RCRA requires.” It also struck down the rule’s exemption of “legacy ponds” (“inactive impoundments at inactive facilities”) from its preventative regulations.

    The “Part A” Rules

    In 2020, EPA finalized a rule (referred to as “Part A”) to respond to the ruling in Utility Solid Waste Activities Group. Among other changes, the rule reclassified clay-lined impoundments as “unlined” impoundments and extended the deadlines in 40 C.F.R. § 257.101(a)(1) and (b)(1)(i) by which unlined impoundments (and those that could not comply with the aquifer location requirement) were required to stop accepting waste and begin closure to “not later than April 11, 2021.” The rule also revised the alternative closure standards in 40 C.F.R. § 257.103 to allow impoundments to continue to receive both CCR and non-CCR waste if the owner or operator demonstrated that there was no alternative disposal capacity on- or off-site and either (1) “it was technically infeasible to complete the measures necessary to obtain alternative disposal capacity … by April 11, 2021”; or (2) the facility was permanently closing a coal-fired boiler. Impoundments qualifying under option (1) could continue to operate until October 2023 or, for impoundments closing because of the Utility Solid Waste Activities Group ruling, October 2024. Impoundments qualifying under option (2) could continue to operate until October 2023 (if 40 acres or smaller) or October 2028 (if larger than 40 acres). In November 2020, several environmental organizations filed a petition for review of the “Part A” rules in the D.C. Circuit in Labadie Environmental Organization v. EPA (Case No. 20-1467), is still, as of October 2024, being held in abeyance while the petitioners review EPA’s decisions on the demonstrations submitted under options (1) and (2), discussed below.

    EPA’s website lists 59 facilities that submitted demonstrations under options (1) and (2). In January 2022, EPA announced that it was proposing:

    In July 2022, EPA proposed to conditionally approve alternative closure deadlines for Calaveras Power Station (San Antonio, Texas) for its sludge recycling holding pond and Mountaineer Power Plant (Letart, West Virginia) for its bottom ash ponds. In October 2022, EPA proposed to conditionally approve an extension in the deadline to close the ash pond at A.B. Brown Generating Station (Mount Vernon, Indiana). And in July 2023, EPA proposed to deny an extension in the deadline to close the ash ponds at Waukegan Generation Station (Waukegan, Illinois). The only proposed determination that was finalized was the determination for Gavin, which was denied effective November 28, 2022. Fourteen facilities withdrew their extension applications because they stopped receiving waste.

    Various affected facilities and the Utility Solid Waste Activities Group filed petitions in the D.C. Circuit for review of EPA’s proposed actions, which were consolidated as Electric Energy, Inc. v. EPA (Case No. 22-1056). A variety of companies and organizations also filed petitions in the D.C. Circuit for review of EPA’s final determination for Gavin, which were consolidated as Electric Energy, Inc. v. EPA (Case No. 23-1035). Both sets of petitions argued that the proposed actions and the final Gavin action effectively amended the existing CCR regulations and imposed new requirements, in violation of RCRA and the Administrative Procedure Act.

    On June 28th, the D.C. Circuit issued an opinion dismissing the petitions challenging both the 2022 proposed actions and the final action on the Gavin Plant’s extension request for lack of jurisdiction, finding that both sets of actions were either consistent with the plain language of the 2015 CCR Rule and EPA’s past applications of that rule or permissible interpretations of ambiguous language in the 2015 CCR Rule. In particular, the court rejected disagreed that the proposed actions effectively “announced” a new “prohibition on closing unlined surface impoundments while coal residuals [sit] in contact with groundwater[,]” finding that the 2015 CCR Rule had “[made that prohibition] clear.” It disagreed that the proposed actions introduced a new requirement “to control the post-closure infiltration of liquids not just ‘downward’ through the final cover system, but also from ‘any direction,’” finding that the 2015 CCR Rule was applicable to infiltrations of liquid from any direction. It disagreed that the 2015 CCR rule did not “apply to facilities that stopped receiving coal residuals before EPA promulgated the 2015 Rule,” finding that such impoundments met the clear regulatory definition of “inactive surface impoundment.” And it found that EPA’s proposed findings that Clifty Creek’s “self-supporting concrete settling tank system is a coal residual surface impoundment,” and that Ottumwa’s use of CCR as “fill” for a closing impoundment did not meet the 2015 CCR Rule’s “beneficial use” exception, were merely interpretations of existing law, not amendments of existing law. Similarly, it found that EPA had not announced any new requirements when it denied the Gavin Plant’s extension request on the basis that the water was “‘freely migrat[ing] in and out of the [coal residuals] remaining in the closet [impoundment].’”

    The owners of the Gavin facility also filed a complaint in the United States District Court for the Southern District of Ohio (Case No. 2:24-cv-41) challenging the denial of their extension requested. That action was stayed pending resolution of the D.C. Circuit action. The stay was lifted in August. The Gavin Plant’s owners filed an amended complaint on August 30th, and the parties stipulated to an extension of the deadline for EPA’s Answer to October 16th.

    The “Part B” Rules

    In 2020, EPA also finalized its “Part B” rule, which amended 40 C.F.R. § 257.71(d) to create a process for EPA (or a participating state) to approve an alternate liner for CCR surface impoundments “constructed without a composite liner or alternate composite liner … .” The rule allowed unlined surface impoundments to continue to operate without retrofitting or closing so long as the owner or operator can demonstrate that the unit will pose “no reasonable probability of adverse effects to human health or the environment.” This demonstration required a two-step process. Initially, a facility was required to submit an application that demonstrated the unit met the minimum requirements, including the existence of sufficient monitoring wells. If approved, the facility would then submit a “demonstration package … certified by a qualified professional engineer,” presenting evidence that “there is no reasonable probability that operation of the surface impoundment will result in concentrations of constituents listed in appendix IV to this part in the uppermost aquifer at levels above a groundwater protection standard.”

    EPA announced that it received eight applications. Two were withdrawn before the end of January 2023. In January 2023, EPA proposed to deny the remaining applications, because it said the facilities “fail[ed] to demonstrate that the surface impoundments complied with the [location or monitoring] requirements of the CCR regulations” and because there was “[e]vidence of potential releases” from some impoundments. As of October 11th, another four of the applications have been withdrawn. EPA still has not finalized any of the proposed denials.

    Legacy Impoundments and CCR Management Units

    On May 18, 2023, EPA proposed regulations to respond to the portion of the 2018 Utility Solid Waste Activities Group ruling that struck down the 2015 CCR Rule’s exemption of “legacy ponds.” EPA finalized these regulations on May 8th, and the final rule is effective on November 4th. Under the final rule, “legacy CCR surface impoundments” (“inactive surface impoundments at inactive facilities”) must “comply with the existing regulations in 40 CFR part 257, subpart D applicable to inactive CCR surface impoundments except for the location restrictions at §§ 257.60 through 257.64, and the liner design criteria at § 257.71.” They must also comply with two new requirements: (1) prepare an applicability report that documents each impoundment’s identifying information, location, and site conditions (or complete a closure certification); and (2) develop a site security plan to “prevent the unknowing entry … and to minimize the potential for the unauthorized entry of people or livestock onto the impoundment.”

    For most legacy CCR surface impoundments, some requirements go into effect on the final rule’s effective date, such as the requirements to prepare an applicability report and a fugitive dust plan and to develop a site security plan. Other requirements, such as the requirement to conduct initial annual inspections, are required within 3 months of the final rule’s effective date. Yet other requirements go into effect 15 months (e.g., compiling a history of construction), 18 months (completing the initial hazard potential classification, structural stability, and safety factor assessments; and preparing an initial inflow design flood control system plan), 30 months (installing a groundwater monitoring system; developing a groundwater sampling and analysis program; and complying with certain groundwater monitoring requirements), 36 months (preparing closure plans and post-closure care plans), or 42 months after the rules effective date (initiating closure). Legacy CCR surface impoundments are required to complete closure within five years after initiating closure.

    The regulations also impose requirements on what EPA calls “CCR management units” (“CCRMU”), which it defines as “any area of land on which any noncontainerized accumulation of CCR is received, is placed, or is otherwise managed, that is not a regulated CCR unit,” such as “inactive CCR landfills and CCR units that closed prior to October 19, 2015.” The definition also includes “other areas where CCR is managed directly on the land.” “[O]wners and operators of active or inactive facilities with a legacy CCR surface impoundment” are required to “conduct a facility evaluation to identify all CCR management units at the facility.” and confirm and document their “presence or absence.” They are required to produce a Facility Evaluation Report in two parts, with the first part due February 9, 2026 and the second part due February 8, 2027. Other, existing CCR requirements would apply to CCR management units, on an extended schedule compared to the requirements for legacy CCR surface impoundments: 42 months (installing a groundwater monitoring system and developing a groundwater sampling and analysis program), 48 months (preparing closure plans and post-closure care plans and initiating closure), or 54 months after the rule’s effective date (initiate closure). And CCR management units, too, are generally required to complete closure within five years after initiating closure.

    EPA’s National Enforcement and Compliance Initiative

    In late 2023, EPA released its National Enforcement and Compliance Initiatives for Fiscal Years 2024-2027. Among the new initiatives adopted was one directed to “Protecting Communities from Coal Ash Contamination” through enforcement of the RCRA CCR rules. EPA explained that this initiative would “focus[ ] on conducting investigations, particularly at coal ash facilities impacting vulnerable or overburdened communities; taking enforcement action at coal ash facilities that are violating the law; and protecting and cleaning up contaminated groundwater, surface water, and drinking water resources.” As part of this initiative, EPA announced in February that it had reached a settlement with Greenidge that required the company to “assess groundwater contamination from the coal ash impoundment at its facility”; “design and implement a corrective action program to address [any] contamination” found; “update and implement a closure plan for the coal ash impoundment”; and “pay a fine of $105,000.”

    State CCR Programs

    RCRA § 4005(d) (42 U.S.C. 6945(d)) allows states to submit applications to take over permitting of CCR units located in their states. The statute requires EPA to approve such applications “if the Administrator determines that the [state] program ... requires each [CCR] unit located in the State to achieve compliance with ... the applicable criteria ... in [40 C.F.R. Part 257]” or alternative state criteria that EPA “determines to be at least as protective as” the federal criteria.

    In December 2021, the Alabama Department of Environmental Management (ADEM) submitted an application for approval of its CCR program. On June 7th, EPA announced that it had denied Alabama’s application. EPA concluded that “Alabama established State CCR regulations that largely mirror the language in the Federal CCR regulations in almost all respects, and, to the extent the provisions are different, the differences in the State regulations are at least as protective as the Federal CCR regulations.” However, EPA found that Alabama “interprets its closure regulations to impose different requirements than those found in the Federal CCR regulations, and ... has issued permits authorizing closures that are inconsistent with the plain language of the Federal CCR regulations.” EPA also found that ADEM had “repeatedly issued permits that authorize groundwater monitoring systems and corrective actions that do not comply with the Federal CCR regulations.” In particular, EPA concluded that “ADEM issued multiple permits allowing CCR in closed units to remain saturated by groundwater, without requiring engineering measures that will control the groundwater flowing into and out of the closed unit[;] ... approved groundwater monitoring systems that contain an inadequate number of wells, and in incorrect locations, to monitor all potential contaminant pathways and to detect groundwater contamination from the CCR units in the uppermost aquifer[; and] ... issued multiple permits that allow the permittee to delay implementation of effective measures to remediate groundwater contamination ... .”

    Interstate Transport of Air Pollution

    Clean Air Act § 110(a)(2)(d) (42 U.S.C. § 7410(a)(2)(D)) requires state implementation plans (SIPs) to contain “adequate provisions” to prevent any State’s sources or other emissions activities from contributing significantly to nonattainment with, or interfering with maintenance of, a NAAQS in another state, or interfering with another state’s prevention of significant deterioration (PSD) measures. This is known as the “Good Neighbor” provision of the Clean Air Act.

    Disapproval of State Implementation Plans

    In 2022, EPA published several Federal Register notices proposing to disapprove almost two dozen states’ SIP submissions for failure to comply with their “good neighbor” obligations under the 2015 ozone NAAQS. In 2023, EPA finalized its disapproval for 19 states (Alabama, Arkansas, California, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Texas, Utah, and West Virginia), partially approved the SIP submissions for Minnesota and Wisconsin, and “deferr[ed] final action” on its proposed disapprovals for Tennessee and Wyoming. EPA explained that it had applied a “4-step … framework to evaluate a state’s obligations to eliminate transport emissions under … the ozone NAAQS:

    (1) “Identify monitoring sites that are projected to have problems attaining and/or maintaining the NAAQS” in 2023 (i.e., “nonattainment or maintenance receptor[s]”);
    (2) “identify states that impact those air quality problems … sufficiently such that the states … warrant further review and analysis”;
    (3) “identify the emissions reductions necessary … to eliminate each … upwind state’s significant contribution to nonattainment or interference with maintenance of the NAAQS at the locations identified in Step 1”; and
    (4) “adopt permanent and enforceable measures needed to achieve those emissions reductions.”

    For step 2, EPA focused on states whose emissions were calculated to contribute at least 1% of the NAAQS (0.70 ppb) “on the days with the highest ozone concentrations at [each problem] receptor based on the 2023 modeling.” And for step 3, “states linked at Steps 1 and 2” were expected to prepare “a multifactor assessment of potential emissions controls” considering cost-effectiveness, total potential emissions reductions, impacts on air quality downwind, and potentially other factors. Applying this framework, EPA disapproved the various states’ SIP submissions. For example, EPA disapproved Ohio’s SIP submission because, among other reasons, Ohio proposed an “alternative definition of maintenance receptors” under Step 1 and “a higher contribution threshold than 1 percent of the NAAQS at Step 2” and failed to properly evaluate “emissions control opportunities” under Step 3.

    Dozens of parties filed petitions for review of EPA’s disapproval of the various states’ “good neighbor” SIP submissions and moved for stays of EPA’s disapproval pending review. Several appellate courts granted petitioners’ motions to stay EPA’s disapproval of various SIPs.

    Issuance of Federal Implementation Plans

    In 2023, EPA published a final rule that included FIP requirements for the 21 states whose SIP submissions were disapproved in whole or in part in February, plus Pennsylvania and Virginia, which failed to submit transport SIPs for the 2015 ozone NAAQS. (Last July, following the Fifth, Sixth, and Eighth Circuits’ issuance of orders staying EPA’s disapproval of the “good neighbor” SIPs for Louisiana, Mississippi, Texas, Arkansas, Missouri, and Kentucky, EPA issued an interim final rule staying the effectiveness of its FIPs for those states.) Starting in 2023, the rule:

    • modified the existing FIPs and emissions budgets for the 12 states already in the CSAPR NOx Ozone Season Group 3 Trading Program created by the Revised CSAPR Update (Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia);
    • transitioned 7 states currently in the CSAPR NOx Ozone Season Group 2 Trading Program (Alabama, Arkansas, Mississippi, Missouri, Oklahoma, Texas, and Wisconsin) to the Group 3 Program; and
    • brought 3 states not currently in any NOx ozone season trading program (Minnesota, Nevada, and Utah) into the Group 3 Program.

    The final rule gave EPA the authority to increase states’ budgets if “more current data on the composition and utilization of the EGU [electric generating unit] fleet” allows it to do so. Also, it modified the Group 3 Trading Program so that, “starting with the 2024 control period, the EPA will annually recalibrate the quantity of accumulated banked allowances under the program to prevent the quantity of allowances carried over from each control period to the next from exceeding the target bank level.” EPA also set “backstop daily emissions rates … for coal steam units greater than or equal to 100 MW in covered states.” For units currently without SCRs, the backstop rates were to go into effect in “the second control period in which newly installed SCR controls are operational at the unit, but not later than the 2030 control period.”

    EPA also imposed NOx emission limits for certain categories of sources beyond electric generating units in 20 states (Arkansas, California, Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, Texas, Utah, Virginia, and West Virginia), starting with the 2026 ozone season. Of interest to this Section, the covered categories of sources included “reciprocating internal combustion engines in Pipeline Transportation of Natural Gas sources.”

    Additionally, on February 16th, EPA published a proposed rule to partially disapprove Arizona, Iowa, Kansas, New Mexico, and Tennessee’s SIP submissions and issue FIPs for those states to address their contribution to downwind nonattainment with, or issues with maintaining, the 2015 ozone NAAQS. The five states would be required to participate in the NOX Ozone Season Group 3 Trading Program starting in 2025. And non-EGUs in Arizona would be required to comply with the NOx limits for non-EGUs, including the limits for reciprocating internal combustion engines used in transporting natural gas.

    As with the prior action, dozens of parties filed petitions for review of EPA’s FIPs and moved for stays of EPA’s disapproval pending review. Several Courts of Appeals stayed those petitions for review pending decisions on the earlier petitions for review challenging EOA’s disapproval of the SIPs. Other petitions were transferred to the D.C. Circuit.

    In August 2023, several associations, companies, and government agencies, including Hybar, LLC, U.S. Steel, Cleveland-Cliffs, and the Arkansas Department of Energy and Environment, Division of Environmental Quality, filed petitions for reconsideration of the “Good Neighbor” FIPs for Arkansas, Minnesota, and more broadly. On March 27th, EPA Administrator Regan signed a notice and sent out letters partially denying those petitions for reconsideration.

    In October 2023, the states of Ohio, Indiana, and West Virginia filed an emergency application for a stay in the United States Supreme Court, arguing that EPA’s FIP rulemaking was flawed and that the Court should stay it while Ohio and other states challenge it in the D.C. Circuit. Among other arguments, the petitioners argued that allowing the FIP rulemaking to go into effect in some states even though it had been stayed in other states, was unfair, unreasonable, and unworkable. Other groups filed similar emergency applications. Surprisingly, the Court scheduled oral argument on the application and directed counsel to “be prepared to address, among other issues related to the challenge … , whether the emissions controls imposed by the Rule are reasonable regardless of the number of states subject to the Rule.” And even more surprisingly, on June 27th, the Supreme Court issued an opinion granting Ohio’s emergency application for a stay. Justice Gorsuch’s five-justice majority opinion held that the challengers were likely to demonstrate that EPA’s action was arbitrary and capricious, because “EPA had determined which emissions-control measures were cost effective at addressing downwind ozone levels based on an assumption that the FIP would apply to all covered states,” and had not explained why removing some states from the FIP would not alter or undermine that cost-effectiveness analysis.

    In response, on August 5th, Joe Goffman (Assistant Administrator of EPA’s Office of Air and Radiation) issued a memorandum announcing that “EPA plan[ned] to comply with the Stay Order by administratively staying implementation of the Plan as to all sources in the geography of the Good Neighbor Plan as promulgated.” The memorandum further stated that EPA would not enforce the Plan’s near-term procedural deadlines for non-EGU sources. However, EPA directed EGUs in Illinois, Indiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and Wisconsin to comply with all “emissions monitoring and reporting requirements” under the CSAPR NOx Ozone Season Group 3 trading program that would have applied prior to the issuance of the 2023 final rule.

    On August 5th, EPA filed a motion in the D.C. Circuit seeking a partial voluntary remand of the FIP “to enable the Agency to take a supplemental final action addressing the record deficiency preliminarily identified by the Supreme Court ... .” On September 12th, the D.C. Circuit granted that motion and remanded the rulemaking without vacatur, “to permit [EPA] to further respond to comments in the record.”

    Mercury and Air Toxics Standards (MATS) Rule

    Section 112 of the Clean Air Act, at 42 U.S.C. § 7412(n)(1)(a), required EPA to study the “reasonably anticipated” public health hazards expected to be caused by hazardous air pollutant (HAP) emissions from electric utility steam generating units, and then to regulate those emissions if EPA concluded doing so was “appropriate and necessary.” In 2000, EPA issued a finding that it was “appropriate and necessary” to regulate HAP emissions from coal- and oil-fired electric generating units. And in 2012, EPA issued the Mercury and Air Toxics Standards (MATS) rule, which set limits on mercury and other HAP emissions from those units.

    On May 7th, EPA finalized several amendments to the MATS rule. The amendments reduced the fPM (filterable particulate matter) emission standard that existing coal-fired EGUs typically use as a surrogate for compliance with the rule’s non-Hg metal standards from 3.0E-02 lb/MMBtu to 1.0E-02 lb/MMBtu. EPA eliminated the option to use stack tests to demonstrate compliance with that fPM standard, leaving continuous emissions monitoring systems (CEMS) as the only way to demonstrate compliance. It also eliminated the separate mercury emission standard for lignite-fired EGUs, which means lignite-fired EGUs will need to “meet the same Hg emission standard as EGUs firing other types of coal” – 1.2 lb/Tbtu or 1.3E-02 lb/GWh, rather than 4.0 lb/Tbtu or 4.0E-02 lb/GWh. EPA also eliminated the second, alternative definition of “startup” in the MATS rule (“[t]he period in which operation of an EGU is initiated for any purpose[,]” ending “4 hours after the EGU generates electricity that is sold or used for any other purpose …, or 4 hours after the EGU makes useful thermal energy … for industrial, commercial, heating, or cooling purposes …, whichever is earlier.”). And rather than removing the alternative total and individual non-Hg metals emissions limits from the MATS rule, as EPA had originally proposed, it reduced those limits “proportional to the finalized fPM emission limit of 0.010 lb/MMBtu.”

    The amendments were effective July 8th. However, affected sources will not need to comply with the new fPM emission standard or the new mercury emission standard for lignite-fired EGUs until July 8, 2027. Moreover, 42 U.S.C. § 7412(i)(3)(B) allows EPA (or a state permitting authority) to “issue a permit that grants an extension [of] up to 1 additional year to comply … .” Affected sources will need to comply with the amendment to the definition of “start-up” starting January 4, 2025, however.

    On May 8th, North Dakota and West Virginia joined 21 other states in filing a joint petition for review in the D.C. Circuit (Case No. 24-1119). The D.C. Circuit Court of Appeals, on August 6th, and then the United States Supreme Court, on October 4th (in NACCO Natural Resources Corp. v. EPA, Nos. 24A178, et al., rejected applications to stay the MATS rule pending judicial review.

    New Source Performance Standards and Existing Source Emissions Guidelines for Fossil Fuel-Fired Electric Generating Units

    Section 111(b) of the Clean Air Act requires EPA to publish, and periodically revise, a “list of categories of stationary sources” that “cause[ ], or contribute[ ] significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.” EPA must then publish standards of performance for new (and modified) sources in those categories (called New Source Performance Standards or NSPS); review those standards at least every 8 years; and revise the standards “if appropriate.” Section 111(d) of the Act, in turn, requires EPA to establish a process under which states submit plans to establish standards of performance for air emissions from existing sources in those same source categories (though not for air pollutants for which EPA has NAAQS or for source categories regulated under Section 112 of the Clean Air Act). Importantly, for both programs, the “standards of performance” should reflect “the degree of emission limitation achievable through the application of the best system of emission reduction” (BSER) that EPA “determines has been adequately demonstrated.”

    In 2023, EPA proposed its replacement to the Obama Administration’s Clean Power Plan and the Trump Administration’s Affordable Clean Energy Rule, neither of which ever went into effect, and to the existing NSPS for new fossil-fuel-fired EGUs. However, EPA withdrew its proposal for existing natural gas combustion turbines. In February, EPA announced that it was “taking a new, comprehensive approach to cover the entire fleet of natural gas-fired turbines, as well as cover more pollutants ... [.]” And on March 26th, EPA announced that it had opened a non-regulatory rulemaking docket “to gather input about ways we can design a stronger, more durable approach to greenhouse gas regulation of the entire fleet of existing gas combustion turbines in the power sector under Clean Air Act Section 111(d).”

    On May 9th, EPA published its final GHG rules for the other types of fossil-fuel-fired EGUs. Surprisingly, the final rule backed away from the proposed rule’s reliace on clean hydrogen as a potential BSER, instead relying solely on carbon capture and storage (CCS) technology. In selecting “add-on controls” as BSER, EPA said that it was sticking to the types of technologies it has traditionally selected as BSER in prior Section 111 rulemakings. But selecting CCS as BSER for certain categories of fossil-fuel-fired EGUs has set the agency up for yet another set of legal challenges (discussed below), this time over whether those controls are “adequately demonstrated.”

    Existing Fossil Fuel-Fired Steam Generating EGUs

    The final BSERs and presumptive standards for existing coal-fired steam generating units vary, depending on when the units’ owners/operators plan to cease operations. There are only two standards, for units ending operations either before or after 2039, with coal-fired units ending operations before 2032 entirely exempt from the regulations. Additionally, EPA moved back the compliance deadline from 2030 to 2032 for coal-fired units that need to implement CCS, to address concerns about grid reliability:

     

    End of Operations BSER Presumptive Standard of Performance Compliance Deadline
    Before January 1, 2032 Exempt
    Before January 1, 2039 Natural gas co-firing at 40% of annual heat input 16% reduction in emission rate January 1, 2030
    After January 1, 2039 90% CCS 88.4% reduction in emission rate January 1, 2032

     

    The BSERs for existing natural gas- and oil-fired EGUs are routine maintenance, with standards of performance based on annual capacity factor “that are slightly higher than at proposal:” 1,600 lb CO2/MWh-gross for intermediate load units, and 1,400 lb CO2/MWh-gross for base-load units. For low-load units, BSER is “uniform fuels” and the presumptive standards are “170 lb CO2/MMBtu for oil-fired sources and ... 130 lb CO2/MMBtu for natural gas-fired sources.”

    Modified Fossil Fuel-Fired Steam Generating EGUs

    For fossil-fuel-fired steam generating units that undertake a modification, EPA chose 90% CCS as BSER, with an 88.4% reduction in emission rate as the standard of performance.

    New and Reconstructed Fossil Fuel-Fired Stationary Combustion Turbines

    For new and reconstructed sources, the BSERs and standards vary depending on the units’ load factors. The final rule dropped EPA’s proposal to have second-phase or alternative standards for units co-firing low-GHG hydrogen. It also chose an earlier second-phase compliance deadline from 2035 to 2032, for base-load units:

     

    EGU Category and Subcategories Phase BSER Compliance Deadline Standard of Performance
    Low-load (peaking) Units

    (capacity factor < 20%)    		 First Use of lower-emitting or “uniform” fuels (e.g., natural gas, distillate oil) The later of startup or the rule’s effective date 120 - 160 lb CO2 / MMBtu, depending on the fuel
    Intermediate-Load Units

    (capacity factor > 20% and < site-specific value based on design efficiency)    		 First Highly efficient generation (“use of high-efficiency simple cycle turbine technology [plus] the best operating and maintenance [O&M] activities”) The later of startup or the rule’s effective date 1,150 lb CO2 / MWh-gross for natural-gas-fired EGUs
    Base-Load Units

    Natural-gas-fired EGUs, nameplate heat input > 2,000 MMBtu/hr

    Natural-gas-fired EGUs, nameplate base load rating between 250 and 2000 MMBtu/hr:    		 First Highly efficient generation (i.e., “use of high-efficiency combined cycle turbine technology [plus] the best [O&M] activities”) The later of startup or the rule’s effective date

    770 lb CO2 / MWh-gross 

     

    Between 770 and 900 lb CO2 / MWh-gross (based on base load rating)
    Second Highly efficient generation and 90% CCS January 1, 2032 90 lb CO2 / MWh-gross

     

    Reliability-Related Instruments

    In response to concerns that the final rule might have threaten the reliability of the electrical grid, EPA introduced new “reliability-related instruments” in the final rule, which it said will allow “affected [existing and new] EGUs to operate at baseline emission rates during documented reliability emergencies,” make available one-year “compliance extensions for unanticipated delays with control technology implementation,” and allow states to delay unit shutdowns that are “forecast to disrupt system reliability.”

    Legal Challenges

    Numerous states filed petitions for review challenging the final GHG regulations for EGUs. West Virginia joined 24 other states in a petition for review filed on May 9th (Case No. 24-1120). Ohio and Kansas filed a separate petition for review the next day (Case No. 24-1121) that was consolidated with Case No. 24-1120, as were the petitions for review filed by numerous trade associations, electric companies, unions, and others.

    On May 17th, the D.C. Circuit denied motions for stay filed by the state petitioners and the National Rural Electric Cooperative Association. And on July 19th, the D.C. Circuit again denied motions to stay the final rule pending appeal, holding that the “Petitioners ha[d] not satisfied the stringent requirements for a stay pending court review.” The court found that the petitioners had not demonstrated that they were likely to prove that EPA “acted arbitrarily or capriciously in determining that carbon capture and other emission control technologies are adequately demonstrated.” And the court rejected petitioners’ suggestion that the “major questions” doctrine applied to the final rule, holding that the rule “falls well within EPA’s bailiwick.” The court also found that there was no immediate need for a stay, because the rule’s earliest compliance deadlines were not until 2030. Several of the petitioners, including Ohio and Kansas, then filed applications for stays of the final rule in the United States Supreme Court. The Court has yet to rule on those applications. In the D.C. Circuit, the parties proposed an expedited briefing schedule, which the court adopted on August 9th. Under the approved schedule, briefing will be completed on November 1st.

    Effluent Limitations Guidelines for Steam Electric Plants

    The 2020 Guidelines

    In 2020, EPA released a final rule revising the effluent limitations guidelines for two waste streams commonly produced by coal-fired steam electric plants: bottom ash transport water and flue gas desulfurization (FGD) water.

    · For FGD wastewater, the rule generally promulgated effluent limitations for mercury, arsenic, selenium, and nitrate/nitrite as nitrogen based on a determination that the “Best Available Technology Economically Achievable” (BAT) was “a combination of chemical precipitation and low hydraulic residence time biological treatment” (LRTR), including ultrafiltration. For high FGD flow plants (those with FGD wastewater flows over 4 million gallons/day, after accounting for the ability to recycle wastewater) and low utilization electric generating units (those with a capacity utilization rating below 10%), the rule set effluent limitations for mercury and arsenic based on chemical precipitation as BAT. And for electric generating units that will permanently stop firing coal by 2028, the rule set “limitations for total suspended solids (TSS) in FGD wastewater” based on surface impoundments as BAT.

    · For bottom ash transport water, the rule generally established BAT as “a high recycle rate system [(HRR)] with a site-specific volumetric purge … which cannot exceed 10 percent of the bottom ash transport water system’s volume … .” For low utilization electric generating units, the rule set “BAT limitations for [bottom ash] transport water for total suspended solids (TSS)” based on surface impoundments as BAT and required implementation of a best management practices (BMP) plan. And for electric generating units that will permanently stop firing coal by 2028, the rule again set numeric TSS limitations based on surface impoundments as BAT.

    For indirect dischargers (discharges to publicly owned treatment works), the rule set pretreatment standards (PSES) identical to the BAT limitations (except for TSS), which indirect dischargers were required to meet by October 13, 2023. For direct discharges, where the rule’s BAT limitations were more stringent than a given source’s previous Best Practicable Control Technology Currently Available (BPT) limitations, local permitting authorities were generally required to set deadlines for compliance no earlier than October 13, 2021, and no later than December 31, 2025. Compliance with the BAT limits for the high flow and low utilization subcategories was generally required by December 31, 2023. Under the rule’s “Voluntary Incentives Program,” however, plants that agreed to “achieve more stringent limitations on mercury, arsenic, selenium, nitrate/ nitrite, bromide, and TSS in FGD wastewater” that are “based on membrane filtration preceded by pretreatment” would have until December 31, 2028, to meet the new requirements.

    Units that intended to take advantage of the alternative limits for low utilization electric generating units or for units that will permanently stop firing coal by 2028 were required to submit a “Notice of Planned Participation” (NOPP) to their permitting authorities or control authorities by October 13, 2021. In November 2021, the Associated Press reported that “at least 26 plants in 14 states” had told state regulators that “they will stop burning coal,” with 21 of those planning to close and the remainder planning to convert to natural gas. In March 2023, EPA released a direct final rule that extended the deadline to submit NOPPs to June 27, 2023, to give additional facilities the opportunity to submit notices stating that they would stop firing coal by 2028.

    Various environmental organizations filed petitions for review of the 2020 rulemaking in the United States Courts of Appeals for the Fourth Circuit and for the D.C. Circuit. These were consolidated in the Fourth Circuit (Appalachian Voices v. EPA, Case No. 20-2187). The case was placed in abeyance in March 2021 to allow the new Biden Administration to review the rule. And it remains in abeyance, pending judicial review of the new rule effluent limitations guidelines discussed below.

    The 2024 Effluent Limitations Guidelines

    On March 8th, EPA announced that it was proposing more stringent effluent limitations guidelines for coal-fired steam electric plants. On May 9th, EPA finalized the effluent limitations guidelines. The 2024 effluent limitations guidelines focused on the same two waste steams as the 2020 rule – bottom ash transport water and FGD wastewater – and also adopted discharge limitations for combustion residual leachate (CRL) and “one subcategory of legacy wastewater.”

    The final rule imposed as BAT limitations “[a] zero-discharge limitation for all pollutants in FGD, BA [bottom ash] transport water, and CRL [combustion residual leachate].” It imposed “[n]umeric (non-zero) discharge limitations for mercury and arsenic in unmanaged CRL and for legacy wastewater discharged from surface impoundments during the closure process” when closure occurs after July 8, 2024 (the rule’s effective date). It eliminated the alternative limits for the high flow and low utilization subcategories. The final rule maintained the alternative limits for “oil-fired and small (50 megawatts (MW) or less) [EGUs]” and for EGUs that will permanently stop firing coal by 2028, however. It also added a new subcategory for EGUs that will permanently stop firing coal by 2034, which are initially subject to “the 2020 rule requirements for FGD wastewater and BA transport water and the pre-2015 BPJ-based BAT requirements for CRL” and then zero discharge limitations after April 30, 2035.

    The PSES for indirect charges from existing sources are the same as the BAT limitations, except for TSS, and do not apply until May 9, 2027. For new affected sources, if any, the rule imposed zero discharge performance and pretreatment standards for CRL.­

    The rule was effective on July 8th. For sources with existing BPT and BAT limitations that are less stringent than the new rule’s requirements, permitting authorities are required to apply the new requirements “as soon as possible … , but no later than December 31, 2029.”

    Numerous petitioners, including Southwestern Electric Power, the Utility Water Act Group, and 22 states, filed challenges to the final guidelines in various circuits. Those petitions were consolidated in the United States Court of Appeals for the Eighth Circuit (Case No. 24-2123). On July 26th, the utility and state Petitioners moved to stay the effluent limitations guidelines pending appeal. On October 10th, the Eighth Circuit denied the motion for stay without comment or explanation.

    Infrastructure Generally

    National Environmental Policy Act

    The National Environmental Policy Act (NEPA) (42 U.S.C. § 4321 et seq.) instructs the Federal Government, at § 4331, “to use all practicable means, consistent with other essential considerations of national policy, to improve and coordinate Federal plans ... to the end that the Nation may ... fulfill the responsibilities of each generation as trustee of the environment for succeeding generations ... .” It also, at § 4332, requires all federal agencies to “ensure that presently unquantified environmental amenities and values may be given appropriate consideration in decisionmaking along with economic and technical considerations,” and to take into account environmental impacts and possible alternatives when recommending or commenting on legislative proposals or “other major Federal actions significantly affecting the quality of the human environment ... .”

    The Biden Administration’s “Phase 1” Rulemaking

    In 2020, under the Trump Administration, the Council on Environmental Quality (CEQ) finalized extensive changes to the NEPA rules that CEQ said would “simplify[ ] and clarify[ ] the requirements” and reduce “excessive paperwork, litigation, and delays.” In 2021, under the Biden Administration, the CEQ proposed to begin “restor[ing] [the] regulatory provisions that were in effect for decades before being modified in 2020.” CEQ finalized that “Phase I” rulemaking in 2022. The “Phase 1” rulemaking reverted 40 C.F.R. § 1502.13 (relating to the “purpose and need” section of the environmental impact statements (EISs) that federal agencies prepare for major federal actions) and 40 C.F.R. § 1507.3 (relating to the requirements for agency NEPA procedures) to their pre-2020 versions. For the definitions of “effects or impacts” in 40 C.F.R. § 1508.1(g), the “Phase 1” rulemaking reversed most of the Trump CEQ’s changes, but retained the portion of the definition that limited “effects or impacts” to “changes to the human environment from the proposed action or alternatives that are reasonably foreseeable … .”

    2023 Amendments to NEPA to Streamline Review

    In 2023, President Biden signed into law Public Law 118-5, the Fiscal Responsibility Act of 2023. Title III included several amendments to streamline NEPA review, some of which echoed the Trump Administration’s amendments to the NEPA rules. Amendments included, but were not limited to, the following:

    · Existing Section 102(C) (42 U.S.C. § 4332(C)): The amendments in this section clarify the required contents for EISs. Under the amendments, agencies are required to describe only those impacts of the proposed action that are “reasonably foreseeable.” The amendments also clarify that the obligation to describe “alternatives to the proposed … action” includes only “reasonable” alternatives “that are technically and economically feasible, and meet the purpose and need of the proposal … .” Agencies must also “include[e] an analysis of any negative environmental impacts of not implementing the proposed agency action … .” The bill further requires that agencies “ensure the professional integrity … of the discussion and analysis in an environmental document; … [and] make use of reliable data and resources … .”

    · New Section 106 (42 U.S.C. 4336): This new section better clarifies when EISs and environmental assessments (EAs) are required. Agencies need not prepare EIS’s or EAs for a proposed agency action that is not “final,” is subject to a “categorical exclusion” under some agency’s law, or is nondiscretionary, or if preparing the document “would clearly and fundamentally conflict with the requirements of another provision of law … .” It also specifies that a proposed action requires an EIS only if the action “has a reasonably foreseeable significant effect on the quality of the human environment.” Otherwise, the “agency shall prepare an [EA],” which “shall be a concise public document … [setting] forth the basis of [the] agency’s finding of no significant impact … .” And, the amendment states that agencies are “not required to undertake new scientific or technical research” to make a NEPA determination “unless the … research is essential to a reasoned choice among alternatives, and the overall costs and time frame of obtaining it are not unreasonable.”

    · New Section 107 (42 U.S.C. 4336a): Among other things, this section imposes page limits and deadlines. EAs “shall not exceed 75 pages, not including any citations or appendices.” EISs “shall not exceed 150 pages, not including any citation or appendices,” except that proposed actions “of extraordinary complexity” get a page limit of 300 pages. EAs must generally be completed within one year, and EISs within two years, unless the lead agency extends the deadline. Project sponsors may bring court actions to enforce these deadlines.

    · New Section 111 (42 U.S.C. 4336e): This new section provides definitions for relevant NEPA terms. The section includes a definition of “major Federal Action,” which excludes, among other things, “general revenue sharing funds which do not provide Federal agency compliance or enforcement responsibility over the subsequent use of such funds”; enforcement actions; and “activities or decisions that are non-discretionary and made in accordance with the agency’s statutory authority.”

    The Biden Administration’s “Phase 2” Rulemaking

    In 2023, the CEQ proposed a “Phase 2” rulemaking,” which it called the “Bipartisan Permitting Reform Implementation Rule.” On May 1st, the CEQ finalized the Phase 2 amendments. The CEQ explained that the 2024 amendments were designed to “implement the amendments to NEPA made by the Fiscal Responsibility Act”; “enhance consistency and clarity”; “improve the efficiency and effectiveness of the environmental review process”; and undo some (but not all) of the Trump Administration’s changes to the NEPA rules. The amendments went into effect on July 1st. A redline of the final amendments to the NEPA regulations is not included in the Federal Register notice, but is available on the CEQ website.

    Among numerous changes, in 40 C.F.R. § 1500.1, the amendments “restore much of the language from the 1978 regulations,” remove language suggesting that NEPA reviews are “merely … a check-the-box exercise,” and restore language “emphasizing the importance of NEPA reviews for informed decision making.” The amendments restore 1500.2, which set out the policies underlying NEPA, and add new text to address climate change and environmental justice. The amendments eliminate the exhaustion and remedies subparagraphs in § 1500.3, which were added in 2020. In § 1501.3(d), they restore language from the 1978 regulations requiring agencies to “examine both the context of an action and the intensity of the effect” in determining whether a proposed action’s adverse effect “is significant.” The new language identifies the “contexts” that should be considered, including “the characteristics of the geographic area, such as proximity to unique or sensitive resources or communities with environmental justice concerns” and, for some actions, “the potential global, national, regional, and local contexts as well as the duration, including short- and long-term effects.” For “intensity,” the new language requires consideration of effects on “unique characteristics of the geographic area,” the uncertainty of “potential effects on the human environment,” effects on resources on the National Register of Historic Places, effects on endangered species, and effects on environmental justice communities. And the new rule language notes that proposed actions may have “an effect [that] is adverse at some points in time and beneficial in others,” and warns agencies “not [to] offset an action’s adverse effects with other beneficial effects to determine significance … .”

    In § 1501.4, the amendments add language stating that categorical exclusions (CEs) should apply only to “categories of actions that normally do not have a significant effect on the human environment, individually or in the aggregate … .” The amendments allow agencies to develop categorical exclusions “through a land use plan, a decision document supported by a programmatic [EIS] or programmatic [EA], or other equivalent planning or programmatic decision,” so long as the agencies meet certain procedural requirements. And the amendments add a new section (d) that offers “a list of examples of features agencies may want to consider including when establishing CEs,” such as “a limited duration” or “mitigation measures that … will ensure that any environmental effects are not significant, so long as a process is established for monitoring and enforcing any required mitigation measures … .”

    In § 1501.5, the amendments require agencies that publish draft EAs to “invite public comment and consider those comments in preparing the final [EA],” but do not require agencies to publish all draft EAs, or to respond to comments for those draft EAs that are published. They also add a new subsection (h), which addresses when agencies should (or may) supplement or reevaluate EAs. For example, agencies should supplement EAs when “[t]he agency makes substantial changes to the proposed action that are relevant to environmental concerns” or “[t]here are substantial new circumstances or information about the significance of the adverse effects that bear on … whether to prepare a finding of no significant impact [FONSI] or an [EIS].” In § 1501.6, the amendments add language reflecting the existing practice of preparing mitigated FONSIs where “the agency determines … that NEPA does not require preparation of an [EIS] because the proposed action will not have significant effects due to mitigation … .” In § 1501.9, the amendments add new language regarding “public and governmental engagement,” including notifications. And in § 1501.10, the amendments add language clarifying the application of the timelines for completing EAs and EISs.

    On May 21st, Iowa and 19 other states filed a complaint challenging the Phase 2 rules in the United States District Court for the District of North Dakota (Case No. 1:24-cv-89). The petitioners (along with a new petitioner, Virginia) filed an amended complaint on June 4th. Parties on both sides have filed cross motions for summary judgment or partial summary judgment, which remain pending.

    Eagle County v. Surface Transportation Board

    On August 18, 2023, the D.C. Circuit Court of Appeals issued an opinion (Case No. 22-1019) granting, in part, petitions objecting to the Surface Transportation Board’s (STB’s) issuance of an order approving the construction of a rail line in Utah. The line was to be developed by the Seven County Infrastructure Coalition and “would connect ‘two termini in the Uinta Basin [of northeastern Utah] … to the national rail network at Kyune, Utah,’” primarily to “transport . . . waxy crude oil produced in the Uinta Basin.” The petitioners, which included the Center for Biological Diversity, alleged that the order violated NEPA and other statutes.

    Under NEPA, the petitioners “argue[d] that the Board failed to take a hard look at the Railway’s environmental impacts in violation of NEPA” for various reasons, including that the STB “ignored certain upstream and downstream impacts of the Railway.” On this point, the D.C. Circuit agreed, for several reasons. First, the court found that the STB had erred when it failed to consider upstream impacts from increased oil production in the Uinta Basin and downstream impacts from increased oil refining in the Gulf Coast. The court noted that STB had estimated how many new oil wells would be drilled because of the project, how much oil would be produced, and which regions would receive the oil for refining. Given this information, the court stated, “the Board provides no reason why it could not quantify the environmental impacts of the wells” or “the emission or other environmental impacts” from the refining. Importantly, the court held that “[t]he Board . . . cannot avoid its responsibility under NEPA to identify and describe the environmental effects of increased oil drilling and refining on the ground that it lacks authority to prevent, control, or mitigate those developments.” Second, the D.C. Circuit agreed that the STB had “failed to take a ‘hard look’ at the increased risk of rail accidents downline given the increased rail traffic resulting from the Railway.” The court agreed that the STB had ­­“relied on national freight train accident rates[, rather than accident rates in the Mountain West,] without explanation and assumed [without basis] that loaded freight trains were as likely to derail as unloaded trains[,]” despite “record evidence noting that there is increased risk from loaded, miles-long oil trains traveling through difficult mountainous terrain.” Third, the D.C. Circuit agreed that the STB’s conclusion that increased train traffic would not increase “downline wildfire risks” was “utterly unreasoned[,]” and instead found that “[a] significant increase in the frequency of which existing ignition sources travel this route equally poses an increased risk of fire.” Fourth, the D.C. Circuit found that the STB had failed to consider impacts from the train line on “downline water resources” such as the Colorado River. For these violations, and numerous other statutory violations detailed in the opinion, the court vacated the order and the STB’s EIS.

    On March 4, Seven County Infrastructure Coalition and Uinta Basin Railway, LLC filed a petition for a writ of certiorari in the United States Supreme Court (Case No. 23-975), asking the Court to answer “Whether the National Environmental Policy Act requires an agency to study environmental impacts beyond the proximate effects of the action over which the agency has regulatory authority.” The Court granted the petition on June 24th. Briefing will be complete on October 18th.

    Food & Water Watch v. FERC

    On June 14th, the D.C. Circuit Court of Appeals issued an opinion (Case No. 22-1214) rejecting a petition for review of a Federal Energy Regulatory Commission (FERC) order granting a certificate of public convenience and necessity to the Tennessee Gas Pipeline Company to “build or expand three compressor stations” for a natural gas pipeline running from Pennsylvania to New York. The petitioner, Food & Water Watch, challenged FERC’s failure to “assess upstream environmental effects” from drilling, to “estimate ... how much ozone would be produced” from the use of the transported natural gas, or to label the downstream GHG emissions and the social costs from the use of the natural gas as “significant or insignificant.” The D.C. Circuit rejected those challenges.

    On the first argument, the D.C. Circuit found that “FERC reasonably concluded that there was too much uncertainty regarding the number and location of additional upstream wells” to “assess upstream environmental effects caused by extracting natural gas from the ground … .” The court found Eagle County v. Surface Transportation Board, discussed above, distinguishable, because the oil wells in that case were all found in one location (the Uinta Basin), whereas “the upstream formations” producing the natural gas to be transported by the new Tennessee Gas pipeline “stretch[ ] at least from southwestern West Virginia into central New York,” and it was unclear how many new wells it would be necessary to drill. On the second argument, the D.C. Circuit found that “FERC reasonably explained” why it could not “give a quantitative estimate of how much ozone would be produced” if the compressor stations were built: because the amount of ozone precursors emitted from combustion of natural gas varies based on the type of use (residential, commercial, or industrial), the specific use (e.g., “home heating, water heating, or cooking”), and meteorological conditions. On the third argument, the D.C. Circuit found that NEPA did not require FERC to “label the increased [GHG] emissions and ensuing costs [from the project] as either significant or insignificant.” The court noted that FERC “quantif[ied] downstream GHG emissions” from the project, “compared those emissions to national and state totals[,]” “explained how increased GHG emissions contribute to climate changes,” and estimated the “climate-related costs” from those emissions. The court found that analysis sufficient.

    New Jersey Conservation Foundation v. FERC

    On July 30th, the D.C. Circuit Court of Appeals issued an opinion (Case No. 23-1064) vacating a FERC order that granted a certificate to the Transcontinental Gas Pipe Line Company, LLC to construct more than 35 miles of natural gas pipelines in Pennsylvania and associated facilities in Pennsylvania and New Jersey. The court’s ruling was based, in part, on its determination that the agency had failed to meet its obligations under NEPA for the project. The court held that FERC’s “decision not to make a case-specific determination about the significance of the Project’s anticipated GHG emissions ... , nor to explain why it believed it could not do so, was arbitrary and capricious.” The court noted that FERC asserted in a 2021 order for Northern Natural Gas Company (174 FERC ¶ 61,189) that it was “[able] to assess the significance of a project’s greenhouse gas (GH?G) emissions [and] those emissions’ contribution to climate change,” and found that FERC had failed to explain why it could not perform a similar assessment here. The court also noted that FERC had estimated the metric tons of CO2e (carbon dioxide-equivalent) emissions that the project would produce (43,548 metric tons of CO2e for construction and 562,044 metric tons of CO2e per year for operation), along with the “social costs” of those emissions ($46 billion), and questioned why FERC could not determine whether those impacts were “significant.” In doing so, the court distinguished its holding in Food & Water Watch v. FERC, discussed above, on the grounds that FERC did not, in this case, “dispute[ ] the premise that it is generally obligated to make a significance determination for each category of emissions” and, instead, arbitrarily “argue[d] that it was unable to do so.” The court also faulted FERC for failing “to assess mitigation strategies for the adverse environmental effects flowing from its approval of the Project.”

    “Waters of the United States”

    As Supreme Court Justice Alito once wrote, the reach of the Clean Water Act is “notoriously unclear.” Sackett v. EPA, 132 S. Ct. 1367, 1375 (2012) (Alito, J., concurring). It can be difficult for a landowner to understand whether wetlands or a small creek on her parcel, for example, are federal waters that require a Clean Water Act (CWA) permit before the landowner can develop the property or cultivate the land. And as noted in a Congressional Research Service report, the definition of “waters of the United States” (WOTUS) may also affect pipeline projects, because it determines the numbers of waters and wetlands into which discharges of dredged or fill material require permits under CWA Section 404.

    In 2020, EPA and the U.S. Army Corps of Engineers published the Navigable Waters Protection Rule in an effort to clarify the scope of federal CWA jurisdiction. But in Pasqua Yaqui Tribe v. EPA, 557 F. Supp. 3d 949 (D. Ariz. 2021), the United States District Court for the District of Arizona issued an order vacating and remanding the Rule. In response, the agencies reverted to the “familiar pre-2015 definition” of WOTUS in 2023. As summarized in the rule preamble, that definition included:

    • Paragraph (a)(1): “traditional navigable waters, the territorial seas, and interstate waters”;
    • Paragraph (a)(2): “impoundments of ‘waters of the United States’”;
    • Tributaries to the first two WOTUS categories that “meet either the relatively permanent standard or the significant nexus standard”;
    • Wetlands that are:
      • adjacent to paragraph (a)(1) waters”;
      • “adjacent to and with a continuous surface connection to relatively permanent paragraph (a)(2) impoundments”;
      • “adjacent to tributaries that meet the relatively permanent standard”; or
      • “adjacent to paragraph (a)(2) impoundments or jurisdictional tributaries” and that “meet the significant nexus standard”;
    • Other “intrastate lakes and ponds, streams, or wetlands … that meet either the relatively permanent standard or the significant nexus standard”;

    The rules explained that waters would meet the “relatively permanent” standard if they “are relatively permanent, standing or continuously flowing bodies of water[,]” borrowing language from Justice Scalia’s plurality opinion in Rapanos v. United States, 547 U.S. 715 (2006). Waters would have a “significant nexus” to WOTUS if they “either alone or in combination with similarly situated waters in the region, significantly affect the chemical, physical, or biological integrity of” WOTUS, borrowing language from Justice Kennedy’s Rapanos concurrence and the CWA’s statement of purpose (in 33 U.S.C. § 1251(a)). And wetlands would be “adjacent” to WOTUS, tributaries, or impoundments if they are “bordering, contiguous, or neighboring” those waters, even if “separated … by … barriers … .”

    Not surprisingly, this WOTUS definition was subject to numerous legal challenges. And on May 25, 2023, the Supreme Court issued its opinion in Sackett v. EPA, 598 U.S. 651 (2023), which rejected the “significant nexus” standard in the 2023 definition of WOTUS. Instead, the Court held that Scalia’s “continuous surface connection” standard from Rapanos was the proper standard for defining WOTUS. Under that standard, the Court held, the CWA extends only to those wetlands that are “as a practical matter indistinguishable from [WOTUS].” Accordingly, a wetland is a WOTUS if: (1) an adjacent body of water constitutes WOTUS, meaning it is a “relatively permanent body of water connected to traditional interstate navigable waters,” and (2) the wetland has a “continuous surface connection with that water,” which makes it difficult to determine where the water ends and the wetland begins.

    EPA and the U.S. Army Corps of Engineers published a final rule on September 8, 2023, removing the “significant nexus” test and revising the definition of “adjacent” to align with the Court’s decision. The U.S. Army Corps of Engineers also resumed issuing approved jurisdictional determinations that were paused pending the Sackett decision. And last November, multiple parties filed amended complaints challenging the September 2023 rulemaking in the Southern District of Texas (Case No. No. 3:23-cv-17) and District of North Dakota (Case No. No. 3:23-cv-32). Another group of associations intervened in the District of North Dakota action and filed their own complaint in December. The parties to the Texas and North Dakota actions have filed cross motions for summary judgment.

      Authors